2010 AEP-EAST INTEGRATED RESOURCE PLAN cases/2011-00401/Kentucky Power Responses to 042312...The...

2010 AEP-EAST INTEGRATED RESOURCE PLAN

2011-2020 Issued: 2010

KPSC Case No. 2011-00401 Sierra Club's Initial Data Requests Dated January 13, 2012 Item No. 3, Attachment 5 of 169

AEP-East 2010 Integrated Resource Plan

The Integrated Resource Plan (IRP) is based upon the best available information at the time of preparation. However, changes that may impact this

plan can, and do, occur without notice. Therefore this plan is not a commitment to a specific course of action, since the future, now more than ever before, is highly uncertain, particularly in light of the current economic

conditions, access to capital, the movement towards increasing use of renewable generation and end-use efficiency, as well as legislative and

regulatory proposals to control carbon, hazardous air pollutants and coal combustion residuals

The implementation action items as described herein are subject to change as new information becomes available or as circumstances warrant. It is AEP’s

intention to revisit and refresh the IRP annually.

The contents of this report contain the Company’s forward-looking projections and recommendations concerning the capacity resource profile of its affiliated operating companies located in the PJM

Regional Transmission Organization. This report contains information that may be viewed by the public. Business sensitive information has been excluded from this document, but will be made

available in a confidential supplement on an as needed basis to third parties subject to execution of a confidentiality agreement. The confidential supplement should be considered strictly business

sensitive and proprietary and should not be duplicated or transmitted in any manner. Any questions or requests for additional copies of this document should be directed to:

Scott C. Weaver

Managing Director—Resource Planning and Operational Analysis

Corporate Planning & Budgeting

(614) 716-1373 (audinet: 200-1373)

[email protected]



Table of Contents Executive Summary................................................................................................................. i 1.0 Introduction and Planning Issues.................................................................................... 1

1.1 IRP Process Overview.........................................................................................................................1 1.2 Introduction to AEP.............................................................................................................................3 1.2.1 AEP-East Zone–PJM:.......................................................................................................................4 1.2.2 AEP-East Pool ..................................................................................................................................4 1.2.3 AEP System Interchange Agreement (East and West) .....................................................................4 1.3 Commodity Pricing .............................................................................................................................5

2.0 Industry Issues and Their Implications .......................................................................... 7 2.1 Environmental Rulemakings and Legislation......................................................................................7 2.1.1 Mercury and Hazardous Air Pollutants Regulation..........................................................................7 2.1.2 Coal Combustion Residuals (CCR) Regulation ...............................................................................7 2.1.3 Transport Rule ..................................................................................................................................8 2.1.4 New Source Review—Consent Decree. ...........................................................................................8 2.1.5 Carbon and Greenhouse Gas (GHG) Legislation .............................................................................8 2.2 Additional Implications of Environmental Legislation – Unit Disposition Analysis ..........................9 2.3 Renewable Portfolio Standards .........................................................................................................10 2.3.1 Implication of Renewable Portfolio Standards on the AEP-East IRP ............................................11 2.3.2 Ohio Renewable Portfolio Standards .............................................................................................14 2.3.3 Michigan Clean, Renewable, and Efficient Energy Act .................................................................15 2.3.4 Virginia Voluntary Renewable Portfolio Standard.........................................................................15 2.3.5 West Virginia Alternative and Renewable Energy Portfolio Standard ..........................................16 2.4 Energy Efficiency Mandates .............................................................................................................16 2.4.1 Implication of Efficiency Mandates: Demand Response/Energy Efficiency (DR/EE) ..................16 2.4.2 Ohio Energy Efficiency Requirements...........................................................................................17 2.4.3 Transmission and Distribution Efficiencies....................................................................................17 2.5 Issues Summary.................................................................................................................................17

3.0 Current Supply Resources ............................................................................................. 19 3.1 Existing AEP Generation Resources .................................................................................................19 3.2 Capacity Impacts of Generation Efficiency Projects.........................................................................19 3.2.1 D. C. Cook Nuclear Plant (Cook) Extended Power Uprating (EPU) .............................................20 3.3 Capacity Impacts of Environmental Compliance Plan ......................................................................20 3.4 Existing Unit Disposition ..................................................................................................................21 3.4.1 Findings and Recommendations—AEP-East Units .......................................................................22 3.4.2 Extended Start-Up ..........................................................................................................................26 3.4.3 Implications of Retirements on Black Start Plan............................................................................26 3.4.4 Applicable PJM Rules ....................................................................................................................27 3.4.5 AEP’s Required Actions and Options ............................................................................................27 3.5 AEP Eastern Transmission Overview ...............................................................................................28 3.5.1 Transmission System Overview .....................................................................................................28 3.5.2 Current System Issues ....................................................................................................................28 3.5.3 PJM RTO Recent Bulk Transmission Improvements.....................................................................29 3.5.4 Impacts of Generation Changes:.....................................................................................................29

4.0 Demand Projections........................................................................................................ 31 4.1 Load and Demand Forecast Process Overview ................................................................................31 4.2 Peak Demand Forecasts.....................................................................................................................33 4.2.1 Load Forecast Drivers ....................................................................................................................35

5.0 Capacity Needs Assessment ........................................................................................... 37 5.1 PJM Planning Constructs - Reliability Pricing Model (RPM) ..........................................................37 5.2 PJM Going In Forecast and Resources..............................................................................................38 5.3 Ancillary Services .............................................................................................................................39



5.4 RTO Requirements and Future Considerations................................................................................. 39 5.5 Capacity Positions—Historical Perspective ...................................................................................... 40

6.0 Resource Options ............................................................................................................ 43 6.1 Resource Considerations ................................................................................................................... 43 6.1.1 Market Purchases ........................................................................................................................... 43 6.1.2 Generation Acquisition Opportunities............................................................................................ 43 6.2 Traditional Capacity-Build Options .................................................................................................. 44 6.2.1 Generation Technology Assessment and Overview....................................................................... 44 6.2.2 Baseload Alternatives..................................................................................................................... 44 6.2.2.1 Pulverized Coal ........................................................................................................................... 45 6.2.2.2 Integrated Gasification Combined Cycle .................................................................................... 45 6.2.2.3 Circulating Fluidized Bed Combustion ....................................................................................... 46 6.2.2.4 Carbon Capture ........................................................................................................................... 47 6.2.2.4.1 Carbon Capture Technology and Alternatives ......................................................................... 47 6.2.2.5 Carbon Storage............................................................................................................................ 48 6.2.2.6 Nuclear ........................................................................................................................................ 48 6.2.3 Intermediate Alternatives ............................................................................................................... 49 6.2.3.1 Natural Gas Combined Cycle (NGCC) ....................................................................................... 49 6.2.4 Peaking Alternatives....................................................................................................................... 50 6.2.4.1 Simple Cycle Combustion Turbines (NGCT) ............................................................................. 51 6.2.4.2 Aeroderivatives (AD) .................................................................................................................. 51 6.2.5 Energy Storage ............................................................................................................................... 52 6.2.5.1 Sodium Sulfur Batteries (NaS):................................................................................................... 52 6.2.5.2 Community Energy Storage (CES) ............................................................................................. 52 6.3 Renewable Alternatives..................................................................................................................... 53 6.3.1 Wind............................................................................................................................................... 54 6.3.2 Solar ............................................................................................................................................... 55 6.3.3 Biomass .......................................................................................................................................... 56 6.3.4 Renewable Energy Certificates (RECs) ......................................................................................... 58 6.3.5 Renewable Alternatives—Economic Screening Results ................................................................ 59 6.4 Demand-Side Alternatives ................................................................................................................ 60 6.4.1 Background .................................................................................................................................... 60 6.4.2 Demand Response .......................................................................................................................... 60 6.4.3 Energy Efficiency........................................................................................................................... 61 6.4.4 Distributed Generation ................................................................................................................... 63 6.4.5 Integrated Voltage/VaR Control .................................................................................................... 63 6.4.6 Energy Conservation ...................................................................................................................... 63

7.0 Evaluating DR/EE Impacts for the 2010 IRP .............................................................. 65 7.1 Demand Response/Energy Efficiency Mandates and Goals ............................................................. 65 7.2 Current DR/EE Programs.................................................................................................................. 65 7.2.1 gridSMART Smart Meter Pilots..................................................................................................... 66 7.3 Assessment of Achievable Potential ................................................................................................. 66 7.4 Utility-sponsored DSM modeling/forecasting .................................................................................. 67 7.4.1 DSM Proxy Resources ................................................................................................................... 68 7.4.2 DSM Levels.................................................................................................................................... 69 7.5 Validating Incremental DR/EE resources ......................................................................................... 70 7.5.1 Energy Efficiency........................................................................................................................... 70 7.5.2 Demand Response .......................................................................................................................... 71 7.5.3 IVVC .............................................................................................................................................. 72 7.6 Discussion and Conclusion ............................................................................................................... 73

8.0 Fundamental Modeling Scenarios................................................................................. 77 8.1 Modeling and Planning Process—An Overview............................................................................... 77 8.2 Methodology ..................................................................................................................................... 77



8.3 Key Fundamental Modeling Pricing Scenarios .................................................................................79 9.0 Resource Portfolio Modeling ......................................................................................... 83

9.1 The Strategist Model .........................................................................................................................83 9.1.1 Modeling Constraints .....................................................................................................................84 9.2 Resource Options/Characteristics and Screening ..............................................................................85 9.2.1 Supply-side Technology Screening ................................................................................................85 9.2.2 Demand-side Alternative Screening...............................................................................................86 9.3 Strategist Optimization......................................................................................................................86 9.3.1 Purpose ...........................................................................................................................................86 9.3.2 Strategic Portfolios .........................................................................................................................86 9.4 Optimum Build Portfolios for Four Economic Scenarios .................................................................87 9.4.1 Optimal Portfolio Results by Scenario ...........................................................................................87 9.4.2 Observations: 2019 Combined-cycle Addition ..............................................................................88 9.4.3 Additional Portfolio Evaluation......................................................................................................89 9.4.3.1 “Retirement Transformation” Plan..............................................................................................89 9.4.3.2 “No CCS Retrofits” Plan .............................................................................................................90 9.4.3.3 “Alternative Resource” Plan........................................................................................................90 9.4.3.4 “Green” Plan................................................................................................................................90 9.4.4 Market Energy Position of the AEP East Zone ..............................................................................91

10.0 Risk Analysis ................................................................................................................. 93 10.1 The URSA Model............................................................................................................................93 10.2 Installed Capital Cost Risk Assessment ..........................................................................................94 10.3 Results Including Installed Capital Cost Risk .................................................................................95 10.4 Conclusion from Risk Modeling .....................................................................................................97

11.0 Findings and Recommendations.................................................................................. 99 11.1 Development of the “Hybrid” Plan .................................................................................................99 11.2 Comparison to 2009 IRP: ..............................................................................................................104

12.0 AEP-East Plan Implementation & Conclusions ...................................................... 105 12.1 AEP-East—Overview of Potential Resource Assignment by Operating Company ......................105 12.2 AEP-East “Pool” Impacts..............................................................................................................107 12.3 New Capacity Lead Times ............................................................................................................107 12.4 AEP-East Implementation Status ..................................................................................................108 12.5 Plan Impacts on Capital Spending.................................................................................................109 12.6 Plan Impact on CO2 Emissions (“Prism” Analysis)......................................................................111 12.7 Conclusions ...................................................................................................................................112



Exhibits Exhibit 1-1: IRP Process Overview ..............................................................................................................2 Exhibit 1-2: AEP System, East and West Zones...........................................................................................3 Exhibit 1-3 Comparison of 2H09 and 1H10 Commodity Forecasts .............................................................5 Exhibit 2-1: Renewable Standards by State ................................................................................................11 Exhibit 2-2: Renewable Energy Plan Through 2030...................................................................................13 Exhibit 2-3: Ohio Renewable Energy Requirement and Plan .....................................................................14 Exhibit 2-4: AEP I&M-Michigan Renewable Requirement and Plan ........................................................15 Exhibit 3-1: AEP-East Capacity (Summer) as of June 2010.......................................................................19 Exhibit 3-2: AEP East Fully Exposed Unit Disposition/Retirement Profile ...............................................23 Exhibit 3-3: Partially Exposed Unit Disposition Profile .............................................................................25 Exhibit 3-4: AEP-PJM Zones and Associated Companies .........................................................................28 Exhibit 4-1: Load and Demand Forecast Process—Sequential Steps .........................................................31 Exhibit 4-2: AEP-East Peak Demand and Energy Projection .....................................................................33 Exhibit 4-3: AEP-East Peak Actual and Forecast (Excludes DSM) ...........................................................34 Exhibit 4-4: AEP-East Internal Energy Actual and Forecast ......................................................................34 Exhibit 5-1: Summary of Capacity vs. PJM Minimum Required Reserves................................................38 Exhibit 5-2: AEP Eastern Zone, Historical Capacity Position ....................................................................41 Exhibit 6-1: Recent Merchant Generation Purchases..................................................................................44 Exhibit 6-2: AEP East Typical Load Duration Curve.................................................................................50 Exhibit 6-3: United States Wind Power Locations .....................................................................................55 Exhibit 6-4: United States Solar Power Locations......................................................................................56 Exhibit 6-5: Land Area Required to Support Biomass Facility ..................................................................57 Exhibit 6-6: Biomass Resources in the United States .................................................................................58 Exhibit 6-7: Renewable Sources Included in AEP-East and AEP-SPP 2010 .............................................59 Exhibit 6-8: Integrated Voltage/VaR Control .............................................................................................63 Exhibit 7-1: AEP-East Embedded DR/EE Programs ..................................................................................65 Exhibit 7-2: Achievable versus Technical Potential (Illustrative)...............................................................67 Exhibit 7-3: DSM Proxy Resources Costs ..................................................................................................68 Exhibit 7-4: Energy Efficiency Impacts......................................................................................................69 Exhibit 7-5: AEP -East Energy Efficiency Program Assumptions .............................................................71 Exhibit 7-6: AEP -East Demand Response Assumptions ...........................................................................72 Exhibit 7-7: AEP -East IVV Response Assumptions..................................................................................73 Exhibit 7-8: Incremental Demand-Side Resources Assumption Summary.................................................75 Exhibit 8-1: IRP Modeling and Planning Process Flow Chart....................................................................78 Exhibit 8-2: Long-term Forecast Process Flow...........................................................................................79 Exhibit 8-3 Commodity Price Forecast by Scenario ...................................................................................81 Exhibit 9-1: Model Optimized Portfolios under Various Power Pricing Scenarios....................................88 Exhibit 9-2: Portfolio Summary..................................................................................................................89 Exhibit 9-3: Optimized Plan Results (2010-2035) Under Various Pricing Scenarios.................................91 Exhibit 9-4: Annual Energy Position of Evaluated Portfolios ....................................................................92 Exhibit 10-1: Key Risk Factors – Weighted Means for 2010 .....................................................................94 Exhibit 10-2: Basis of Installed Capital Cost Distributions ........................................................................94 Exhibit 10-3: Risk -Adjusted CPW 2010-2035 Revenue Requirement ($ Millions) ..................................95 Exhibit 10-4: Distribution Function for All Portfolios................................................................................96 Exhibit 10-5: Distribution Function for All Portfolios at > 95% Probability..............................................96 Exhibit 11-1: Hybrid Plan .........................................................................................................................101 Exhibit 11-2: AEP-East Generation Capacity...........................................................................................102 Exhibit 11-3: Change in Energy Mix with Hybrid Plan Current vs. 2020 and 2030.................................103 Exhibit 11-4: Comparison of 2010 IRP to 2009 IRP ................................................................................104 Exhibit 12-1: Projected AEP-East Reserve Margin, By Company and System for IRP Period................106 Exhibit 12-2: Incremental Capacity Settlement Impacts of the IRP .........................................................107 Exhibit 12-3: New Capacity Lead Times..................................................................................................107 Exhibit 12-4: Incremental Capital Spending Impacts of the IRP ..............................................................110 Exhibit 12-5: AEP-East System CO2 Emission Reductions, by “Prism” Component ..............................112



Appendices Appendix A, Figure 1 Existing Generation Capacity, AEP-East Zone.....................................................116 Appendix A, Figure 2 Existing Generating Capacity, AEP-East Zone (cont’d).......................................117 Appendix B, Figure 1 Assumed FGD Scrubber Efficiency and Timing...................................................118 Appendix B, Figure 2 Assumed Capacity Changes Incorporated into Long Range Plan .........................119 Appendix C, Key Supply Side Resource Assumptions.............................................................................120 Appendix D, AEP-East Summer Peak Demands, Capabilities and Margins ............................................121 Appendix E, Plan to Meet 10% of Renewable Energy Target by 2020 ....................................................122 Appendix F, Figure 1, Internal Demand by Company..............................................................................123 Appendix F, Figure 2, Internal Demand by Company..............................................................................124 Appendix F, Figure 3, Internal Demand by Company..............................................................................125 Appendix F, Figure 4, Internal Energy by Company................................................................................126 Appendix F, Figure 5, Internal Energy by Company................................................................................127 Appendix G, Figure 1, DSM by Company ...............................................................................................128 Appendix G, Figure 2, DSM by Company ...............................................................................................129 Appendix H, Ohio Choice by Company ...................................................................................................130 Appendix I, Renewable Energy Technology Screening ...........................................................................131 Appendix J, Capacity Additions by Company..........................................................................................132 Appendix K, Load Forecast Modeling......................................................................................................133 Appendix L, Capacity Resource Modeling (Strategist) and Levelized Busbar Costs...............................137 Appendix M, Utility Risk Simulation Analysis (URSA) Modeling .........................................................140



Acknowledgements

The Resource Planning group appreciates the support and input of the various individuals

throughout the Service Corporation who provided input into the development of this Integrated Resource Plan document. In addition, a number of people provided valuable comments as the report was being developed including the operating company regulatory support staffs.



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Executive Summary The goal of resource planning for a largely regulated utility such as AEP is to cost-effectively

match its energy supply needs with projected customer demand. As such the plan lays out the amount, timing and type of resources that achieve this goal at the lowest reasonable cost, considering all the various constraints—reserve margins, emission limitations, renewable and energy efficiency requirements—that are currently mandated or projected to be mandated.

Planning for future resource requirements during volatile periods can be challenging. The robustness and timing of economic recovery and its impact on load, commodity prices, varying levels of proposed or emerging environmental legislation or federal regulation regarding greenhouse gases/carbon dioxide (GHG/CO2), hazardous air pollutants (HAPs), coal combustion residuals (CCR) as well as existing and proposed mandates for renewable energy and demand-side management (DSM) represent major “drivers” of uncertainty that must be addressed during this planning process.

This Executive Summary provides high-level results of the Integrated Resource Plan (IRP or “Plan”) process and analyses for the AEP-East zone of the AEP system covering the 10-year period 2011-2020 (Planning Period), with additional modeling and analyses conducted through 2030 (Study Period).1

The following Summary Exhibit 1 offers the “going-in” capacity need of each of the AEP-East zone prior to uncommitted capacity additions. It amplifies that the region’s overall capacity need does not occur until the end of the Planning Period (2018-2019). “Committed” new capacity embedded in this Plan includes completion of the 540 MW Dresden combined cycle facility in 2013, the assumed performance of the Donald C. Cook Nuclear Plant Extended Power Uprate (EPU) project, and assumed near-term execution of purchase power agreements for renewable energy (largely, wind) resources.

This going-in capacity profile also considered the potential retirement of close to 6,000 MW of primarily older, less-efficient coal-fired units over the Planning Period due largely to external factors including known or anticipated environmental initiatives from the U.S. Environmental Protection Agency (EPA), as well as the December 2007 stipulated New Source Review (NSR) Consent Decree. In spite of this potential, this AEP-East IRP requires no new baseload capacity resources in the forecast period. Rather, the proposed EPU initiative at the Cook Nuclear Station during the 2014-2018 time period and peaking resources required in 2017 and 2018, in addition to wind purchases and DSM are assumed to be added to maintain anticipated minimum PJM capacity reserve margin requirements (approximately 15.5% of peak demand) as well as system reliability/restoration needs. It is anticipated that additional natural gas-fired peaking and intermediate capacity would be added shortly after the 2020 Planning Period to meet future load obligations.

1 Whereas this document focuses on collective affiliate Operating Company planning requirements of the “AEP-West” zone companies operating within the Southwestern Power Pool (SPP) Regional Transmission Organization (RTO), or “AEP-SPP”, comparable planning has also been performed for the affiliate East zone AEP Operating Companies residing in the PJM RTO.



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Summary Exhibit 1

AEP-East

"Going-In" PJM Capacity (UCAP) Position

NO CAPACITY ADDITIONS (Post-Dresden and Cook EPU)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

32,000

2010

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2030

PJM Planning Year (Eff: 6/1/XXXX)

MW

Cumul Retirements (5930 MW by 2019-20 PY)

Cook EPU (2014-18)

Dresden (2013)

UCAP w/o New Additions

UCAP Obligation/Demand_Apr '09 Demand Fcst ('09 IRP)


Source: AEP Resource Planning

The following Summary Exhibit 2 demonstrates AEP-East’s capacity position relative to this PJM reserve requirement, now inclusive of capacity additions as proposed in this 2010 IRP. As this table indicates, the combination of traditional supply-side additions and demand-side measures that provide demand reductions/energy efficiency (DR/EE) allow AEP-East to meet this PJM reserve margin criterion.



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Summary Exhibit 2

AEP-East PJM ViewReflecting: Current Hybrid Plan

15,000

17,000

19,000

21,000

23,000

25,000

27,000

29,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

MW

- S

umm

er C

apac

ity

Remaining Existing Capacity (MW) Dresden Capacity (MW)

New Generation (MW) Total Obligation (MW)

Total Obligation (MW) (Excluding DR/EE/IVV)

Planning Period Study Period


Major Drivers Load

Anticipated load and peak demand is one of the chief underpinnings of the planning process. Over the 10-year Planning Period, the AEP-East region’s internal demand profile has a 0.71% Compound Annual Growth Rate (CAGR). This equates to an approximate 150 MW per year increase over the Planning Period if the load growth was uniform. This is considerably lower than the CAGR projected in the previous, 2009 IRP load forecast of 1.31 percent, or about 280 MW annually. This lower growth rate obviously delays the need for replacement capacity even with the prospect of accelerated AEP-East coal unit retirements.

Commodity Pricing

AEP updates its commodities forecast twice each year. The Fall of 2009 forecast (2H09 Forecast) was used as the basis for resource modeling in this IRP process. After comparing the 2H09 Forecast to the subsequent long term forecast prepared in the Spring of 2010 (1H10 Forecast), as shown in Summary Exhibit 3, it was apparent that the effects of the recently-revised pricing estimates were not significant in determining future resource additions and did not warrant a new



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resource evaluation. Note that with the economic recovery, prices for on-peak power, coal and natural gas will rise in real terms over the next 3 to 5 year period and then remain relatively stable.

Summary Exhibit 3

Commodity Price Comparison 2H09 to 1H10

CAPP Coal 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

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1.00

2.00

2010

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2030

2H09 CAPP 1H10 CAPP

Index Calculated Using Real $

PRB Coal 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

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1.00

2.00

2010

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2H2009 1H2010


TCO Delivered Gas 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

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2H2009 1H2010


On Peak Power PJM AEP Hub - 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

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1.00

2.00

3.00

2010

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2H2009 1H2010


CO2 Emission Costs/Tonne - 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2014 = 1.0)

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1.00

2.00

3.00

2010

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2H2009 1H2010


Potential Carbon Legislation

There has been much activity and discussion in Congress regarding legislation to require reductions in GHG/CO2 emissions. In this 2010 IRP it has been assumed that such legislated or regulated carbon restrictions will ultimately be established. The pricing assumptions and requirements for CO2 used in this IRP were developed after the U.S. House passage of the Waxman-Markey Bill. Future IRPs will naturally reflect legislation (or regulation) that is enacted or developed after this report is issued. The driving planning assumptions around Climate Change in this 2010 IRP include substantive GHG/CO2 reduction legislation effective by 2014 with an economy-wide cap-and-trade



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regime effective in the same year. Although Waxman-Markey assumes a 2012 start-date, and more recent legislation introduced in the Senate (“Kerry-Lieberman” Discussion Draft) assumes a 2013 start-date, the assumption is that such comprehensive GHG/CO2 legislation will not be approved by Congress this year and, as such, will not be effective until at least 2014.

Proposed EPA Rulemaking

The 2010 IRP considered potential future U.S. EPA rulemaking around HAPs. According to the AEP Environmental Services group, such federal rulemaking for HAPs could become effective by as early as the end of 2015 when a “command-and-control” policy could require all U.S. coal and lignite units to install Maximum Available Control Technologies (MACT) including (combined) Flue Gas Desulphurization (FGD), Selective Catalytic Reduction (SCR), as well as, potentially, Activated Carbon Injection (ACI) with fabric filter emissions control equipment for mercury and numerous other heavy metals, toxic compounds, and acid gases.

In addition, new rules on the handling and disposal of CCR are also being developed and could likewise be implemented as early as 2017, requiring significant additional capital investment in the coal fleet to convert “wet” flyash and bottom ash disposal equipment and systems—including attendant landfills and ponds—to “dry” systems, plus build waste-water treatment facilities to address plant groundwater run-off. Further, the federal EPA has also recently issued proposed rulemaking to replace the former Clean Air Interstate Rules (CAIR) for sulfur dioxide (SO2), oxides of nitrogen (NOX), and particulate matter (PM), which had previously been vacated by the federal courts. In lieu of a national cap-and-trade for those effluents, this “Transport Rule” would potentially establish state-specific emission budgets for SO2 and both Annual and Seasonal (May-September) NOX. In the AEP-East zone states (Indiana, Kentucky, Ohio, Virginia and West Virginia), such proposed Transport Rule emission reduction requirements are likewise contentious in that it would theoretically involve acceleration of already-planned environmental retrofits to as early as January, 2014; in-service dates that may be implausible to achieve.

In summary, the cumulative cost of complying with these collective emerging environmental rules could ultimately be hugely burdensome on the AEP-East Operating Companies and its customers. Therefore, such requirements, if formally established by EPA, could then also accelerate proposed retirement dates of any currently non-retrofitted coal unit in the AEP-East fleet as established within this 2010 IRP as discussed below.

Additional Potential Coal Unit Dispositions

An AEP-East unit disposition study was undertaken by an IRP Unit Disposition evaluation team involving numerous AEP functions. As in the past, the team’s primary intent was to assess the relative composition and timing of potential unit retirements. As in previous reviews, the predominant focus in the East was again on the roughly 5,300 MW of older-vintage, less-efficient, non-environmental control-retrofitted (i.e., “Fully-Exposed”) coal units in the AEP-East fleet.



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As suggested above, in this 2010 IRP cycle review, the team considered financial implications of the potential (dispatch) cost impacts associated with CO2 emissions, as well as cost to comply with assumed HAPs rulemaking. In addition, factors including PJM operational flexibility, emerging unit liabilities, and workforce/community impacts were considered when recommending the relative multi-tier profile of potential unit retirements.

It should be noted that the conclusions of this updated unit disposition study are for the expressed purpose of performing this overall long-term IRP analysis and reflect on-going and evolving disposition assessments. From a capacity perspective, no formal decisions have been made with respect to specific timing of any such unit retirements, with the exception of those units that are identified in the stipulated Consent Decree related to the NSR litigation.

AEP has assumed for planning purposes that all of the “Fully-Exposed” coal units in the AEP-East fleet would be retired over the course of the decade under the notion that the implementation of any U.S. EPA HAPs and/or CCR rulemaking would be potentially “extended and staggered” beyond end-of 2015 in recognition of the national exposure (i.e., roughly 1/3 of U.S. coal units that are likewise fully-exposed and not likely to be retrofitted to achieve such rules.) Moreover, given the relative ‘retrofit vs. retire’ economics, it is further assumed that OPCo’s Muskingum River Unit 5—a relative newer, more thermally-efficient 600-MW coal unit—would likewise be retired in the mid-to-late Planning Period... for a total of nearly 6,000 MW of coal unit retirements.2

Carbon Capture and Storage Technology

While the 2010 IRP does not include any coal-fired baseload additions, it does recognize that the existing fossil fleet will likely be subject to CO2 emission reduction requirements in the future be it through legislated or regulated means. Therefore, the Plan includes the continued development and phase-in of Carbon Capture and Storage (CCS) at the (APCo) Mountaineer Plant as a practical, technology-advancing strategy. AEP has received partial funding from the U.S. Department of Energy (DOE) on the proposed Phase 2 (235-MW slipstream) CCS initiative at Mountaineer. Projects such as this one will position us well should legislation provide for “Bonus Allowances”. Both the Waxman-Markey Bill and the (Draft) Kerry-Lieberman comprehensive climate change legislation in the U.S. Senate offer such “Bonus Allowance” provisions.

Assuming such CCS Bonus Allowances are available, this 2010 AEP-East IRP has also assumed that both the APCo Mountaineer Station and a unit at the OPCo Gavin Station (combined 2,600 MW) would have CCS fully-installed toward the end of the Planning Period in 2019-2020.

2 For 2010 Plan purposes, other than Muskingum River U5, all other comparable AEP-East “Partially-Exposed” coal units not currently fully-retrofitted to meet either NSR Consent Decree or anticipated HAPs rulemaking requirements (Big Sandy Unit 2, Rockport Units 1&2, Conesville Units 5&6) are assumed to be retrofitted and would continue operation throughout the Study Period.



vii

Peak Demand Response and Energy Efficiency

Recognizing the prospects of higher marginal or “avoided” costs, AEP initiatives to improve grid efficiency and install advanced metering, as well as a national groundswell focused on usage efficiency, the AEP-East 2010 IRP reflects approximately 415 MW of incremental peak demand reduction (above the 473 MW of interruptible load currently in place) by the end of 2011, growing to 1,213 by the end of 2014.

These incremental reductions in peak demand result from a suite of sources including:

“Passive” demand reductions via customer-focused energy efficiency (“24/7”-type) programs (560 MW);

“Active” demand response (“peak shaving”-type) program opportunities (600 MW); and unique utility infrastructure efficiency initiatives such as Integrated Volt/Var Control

(IVVC) (53 MW).

Further, this Plan fully reflects legislative and regulatory mandated levels of AEP-East Operating Company energy efficiency and demand response in Ohio, Indiana and Michigan.

Wind and Other Renewable Resources

Along with the prospects of comprehensive GHG/CO2 legislation—or even as a “carve-out” as part of any potential Energy Bill that could be contemplated in Congress—the possible introduction of a Federal Renewable Portfolio Standard (RPS) has resulted in the planned AEP system-wide addition of 2,000 MW of renewable resources by approximately mid-decade, or end-of-2014. Note that this represents an approximate 3-year shift from prior (2009 IRP) planned commitments of 2,000 MW of System-wide renewable resources by the end of 2011; however, as recent unfavorable regulatory decisions in both Virginia and Kentucky surrounding cost recovery of planned wind purchase transactions has resulted in this “extension” of that prior goal.

The largest portion of these additions (about 1,100 MW nameplate of, predominantly, wind resources) is assumed to be applicable to AEP-East. Placed in addition to current and planned AEP-SPP region affiliates—Public Service Company of Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO)—long-term wind development/purchases as well as economically-screened biomass co-firing opportunities, the overall AEP System is positioned to achieving a target of 10 percent of energy sales from renewable sources by the end of the IRP Planning Period (2020), again consistent with Ohio Substitute S.B. 221 and other state-mandated renewable requirements in Michigan, West Virginia, Oklahoma and Texas.

Emerging Technologies

AEP is committed to pursuing emerging technologies that fit into the capacity resource planning process including, among others, fuel cells, solar, energy storage as well as “smart-grid” enabling meters and distribution infrastructure. These largely distributed technologies, while currently expensive relative to traditional demand and supply options—and in consideration of AEP-East’s current capacity and energy “length” in PJM—have the capability to evolve into far more common



viii

and accepted resource options as costs come down and performance/efficiencies continue to improve. For each of these options, both the technology and associated costs will continue to be very closely monitored for inclusion in future annual planning cycles.

As an example, the 2010 AEP-East IRP includes the addition of IVVC technology into the distribution system infrastructure which will reduce voltages and, hence customer usage behind the meter. This technology therefore helps cost-effectively mitigate the need for new capacity and reduces energy requirements resulting in reduced emissions.

Portfolio Risk Analysis

Given the uncertainties facing AEP in the future, a number of diverse resource portfolios were analyzed under a wide range of future commodity pricing scenarios. This allowed the resource planners to evaluate whether near-term decisions may adversely impact future costs to customers. The portfolios that were evaluated include accelerated near-term coal unit retirements (over-and-above Muskingum River U5), additional DR/EE and renewable resources, the addition of nuclear capacity, as well as various combinations of these end-states under various commodity pricing scenarios. This exercise provided intelligence in establishing the final recommended plan.



ix

AEP-East Recommended Plan: 2011-2020 (Including AEP-East Company Responsibility)

Complete the 540 MW Dresden Combined Cycle Facility by 2013 (AEG-APCo)

Retire 5,930 MW of coal-fired generating units over the period: 2012-to-2019 (Various), including the 600 MW Muskingum River Unit 5 (OPCo)

As part of the life extension component replacement program required under the 20-year operating license extension received in August 2005, uprate the D.C. Cook Units 1 and 2 by 417 MW over the 2014 to 2018 timeframe (I&M)

Construct or acquire peaking duty cycle (e.g., Combustion Turbine) capacity: 314 MW by 2017 (APCo), and an additional 314 MW by 2018 (KPCo/APCo) for both ultimate capacity and anticipated system reliability/restoration (“Black Start”) requirements

Purchase or construct an additional 1,600 MW (nameplate) of wind generation by 2020 (Various), over-and-above the 626 MW already in operation, to achieve both state-mandated renewable requirements (OH, MI, WVa) as well as contribute to a 10% (of retails sales) “target” by 2020

Co-fire with biomass feedstock at existing units, or acquire the “equivalent” of approximately 150 MW of dedicated biomass generation by 2018 (CSP, OPCo, & APCo)

Purchase or construct an additional 215 MW (nameplate) of solar generation for the AEP-Ohio Companies (CSP and OPCo) in order to achieve “solar-specific” renewable mandates set forth under Ohio S.B. 221, in addition to the 10 MW solar (Wyandot) PPA already in operation

Continue the Carbon Capture and Storage (CCS) project at Mountaineer (APCo) and ultimately fully install CCS at Mountaineer and Gavin Unit 1 (OPCo) by 2020 3

Implement Energy Efficiency programs totaling over 6,000 GWh (868 MW of attendant “passive” Demand Response) by 2020 across all AEP-East states/companies to meet either legislative or regulatory mandated (OH, MI, IN) requirements or, incrementally, known/anticipated initiatives in non-mandated states

Implement “Active” Demand Response initiatives totaling 600 MW by 2015 (Various)

Upgrade the distribution system with IVVC technology, reducing (peak) demand by 106 MW and customer energy usage totaling roughly 500 GWh by 2018 (Various)

3 Any CCS implementation beyond the current Mountaineer “Phase 2” (235-MW slipstream) project would be subject to qualification and receipt of cost-offsetting “(CO2) Bonus Allowances” emanating from potential comprehensive Climate Change legislation currently before the U.S. Congress.



x

The following Summary Exhibit 4 offers a view of the 2010 AEP-East IRP:

Summary Exhibit 4

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xi

Plan Impact on Capital Requirements

This Plan includes new capacity resource additions, as described, as well as unit uprates and assumed environmental retrofits. Such generation additions require a significant investment of capital. Some of these projects are still conceptual in nature, others do not have site-specific information to perform detailed estimates; however, it is important to provide an order of magnitude cost estimate for the projects included in this plan. As some of the initiatives represented in this plan span both East (and West) AEP zones, this Summary Exhibit 5 includes estimates for such projects over the entire AEP System.

Summary Exhibit 5

AEP System

2010 IRP CycleMajor Environmental & New Generation

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

$ M

illio

ns

Carbon Capture--Var Oper Cos.

Dry Fly Ash Conv--Var Oper. Cos.

Southwestern Electric Power

Public Service of Oklahoma

Ohio Power

Kentucky Power

Indiana Michigan Power

Columbus Southern Power

Appalachian Power

AEP Generating Company

Carbon Capture--Var Oper Cos. - - - - - - 746 1,861 2,000 1,618

Dry Fly Ash Conv--Var Oper. Cos. - 12 34 52 86 28 43 62 - -

Southwestern Electric Power 236 187 95 87 320 488 366 377 330 142

Public Service of Oklahoma 6 9 0 5 127 258 366 364 172 299

Ohio Power 40 43 66 77 65 28 30 36 62 63

Kentucky Power 23 104 174 207 145 75 76 56 65 76

Indiana Michigan Power 47 70 81 257 458 360 418 261 252 19

Columbus Southern Power 21 27 20 25 100 141 69 103 133 55

Appalachian Power 107 52 66 185 248 222 141 63 122 155

AEP Generating Company 5 90 37 50 140 253 380 232 252 18

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020


It is important to reiterate the capital spend level reflected on the Summary Exhibit 5 is “incremental” in that it does not include “Base”/business-as-usual capital expenditure requirements of the generation facilities or transmission and distribution capital requirements. Achieving this additional level of expenditure will therefore be a significant challenge going-forward and would suggest the Plan itself will remain under constant evaluation and is subject to change as, particularly, AEP’s system-wide and operating company-specific “Capital Allocation” processes continue to be refined. Also, while the spend level includes cost to install Carbon Capture equipment, these projects are included only under the assumption that any comprehensive GHG/CO2 bill requiring significant



xii

reductions in CO2 emissions will include a provision to receive credits or allowances that would largely offset the cost of such equipment.

Conclusions

The recommended AEP-East capacity resource plan reflected on Summary Exhibit 4 provides the lowest reasonable cost solution through a combination of traditional supply, renewable and demand-side resources. The most recent (April 2010) “tempered” load growth, combined with the completion of the Dresden natural gas-combined cycle facility, additional renewable resources, increased DR/EE initiatives, and the proposed capacity uprate of the Cook Nuclear facility allow AEP-East region to meet its reserve requirements until the 2018-2019 timeframe, at which point modeling indicates new peaking capacity will be required. Other than the aforementioned D.C. Cook uprate, no new baseload capacity is required over the 10-year Planning Period.

The Plan also positions the AEP-East Operating Companies to achieve legislative or regulatory mandated state renewable portfolio standards and energy efficiency requirements, and sets in place the framework to meet potential CO2 reduction targets and emerging U.S. EPA rulemaking around HAPs and CCR at the intended least reasonable cost to its customers.

The resource planning process is becoming increasingly complex given these uncertainties as well as spiraling technological advancements, changing economic and other energy supply fundamentals, uncertainty around demand and energy usage patterns as well as customer acceptance for embracing efficiency initiatives. All of these uncertainties necessitate flexibility in any on-going plan. Moreover, the ability to invest in capital-intensive infrastructure is increasingly challenged in light of current economic conditions, and the impact on the AEP-East Operating Companies’ customer costs-of-service/rates will continue to be a primary planning consideration.

Other than those initiatives that fall within some necessary “actionable” period over the next 2-3 years, this long-term Plan is also not a commitment to a specific course of action, since the future, now more than ever before, is highly uncertain, particularly in light of the current economic conditions, the movement towards increasing use of renewable generation and end-use efficiency, as well as legislative and regulated proposals to control greenhouse gases and numerous other hazardous pollutants… all of which will likely result in either the retirement or costly retrofitting of all existing AEP-East coal units.

Finally, bear in mind that the planning process is a continuous activity; assumptions and plans are continually reviewed as new information becomes available and modified as appropriate. Indeed, the resource expansion plan reported here reflects, to a large extent, assumptions that are clearly subject to change. In summary, it represents a very reasonable “snapshot” of future requirements at this particular point in time.



1

1.0 Introduction and Planning Issues

This report documents the processes and assumptions required to develop the recommended integrated resource plan (IRP or the “Plan”) for the AEP-East System. The IRP process consists of the following steps:

Describe the company, the resource planning process in general (Section 1).

Describe the implications of current issues as they relate to resource planning (Section 2).

Identify current supply resources, including projected changes to those resources (e.g. de-rates or retirements), and transmission system integration issues (Section 3).

Provide projected growth in demand and energy which serves as the underpinning of the plan (Section 4).

Combine these two projected states (resources versus demand) to identify the need to be filled (Section 5).

Describe the analysis and assumptions that will be used to develop the plan such as future resource options (Section 6), evaluation of demand side measures (Section 7), and fundamental modeling parameters (Section 8).

Perform resource modeling and use the results to develop portfolios, including the selection of the ultimate “Hybrid Plan” (Section 9).

Utilize risk analysis techniques on selected portfolios (Section 10).

Present the findings and recommendations, plan implementation and, finally, plan implications on AEP East operating companies (Sections 11 and 12).

1.1 IRP Process Overview

This report presents the results of the IRP analysis for the AEP East (PJM) zone of the AEP System, covering the ten year period 2011-2020 (Planning Period), with additional planning modeling and studies conducted through the year 2030 (extended Study Period). The information presented in this IRP includes descriptions of assumptions, study parameters, methodologies, and results including the integration of supply and demand side resources.

In addition to the need to set forth a long-term strategy for achieving regional reliability/reserve margin requirements, capacity resource planning is critical to AEP due to its impact on:

Capital Expenditure Requirements

Rate Case Planning

Integration with other Strategic Business Initiatives e.g., corporate sustainability goals, environmental compliance, transmission planning, etc

The goal of the IRP process is to identify the amount, timing and type of resources required to ensure a reliable supply of power and energy to customers at the lowest reasonable cost.

The IRP process is displayed graphically in Exhibit 1-1.



2

Exhibit 1-1: IRP Process Overview


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3

1.2 Introduction to AEP

AEP, with more than five million American customers and serving parts of 11 states, is one of the country’s largest investor-owned utilities. The service territory covers 197,500 square miles in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia (see Exhibit 1-2).

Exhibit 1-2: AEP System, East and West Zones

Source: AEP Internal Communications

AEP owns and/or operates 80 generating stations in the United States, with a capacity of approximately 38,000 megawatts. AEP’s customers are served by one of the world’s largest transmission and distribution systems. System-wide there are more than 39,000 circuit miles of transmission lines and more than 214,000 miles of distribution lines.

AEP’s operating companies are managed in two geographic zones: Its eastern zone, comprising Indiana Michigan Power Company (I&M), Kentucky Power Company (KPCo), Ohio Power Company (OPCo), Columbus Southern Power Company (CSP), Appalachian Power Company (APCo), Kingsport Power Company (KgP), and Wheeling Power Company (WPCo); and its western zone, which, for resource planning purposes within the Southwest Power Pool (SPP), comprises the Public Service Company of Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO).4 CSP and OPCo operate as a single business unit called AEP-Ohio.

4 Both KgP and WPCo are non-generating companies purchasing all power and energy under FERC-approved wholesale contracts with affiliates APCo and OPCo, respectively. AEP also has two operating companies that reside in the Electric Reliability Council of Texas (ERCOT), AEP Texas North Company (TNC) and Texas Central Company (TCC). These companies are essentially “wires” companies only, as neither owns nor operates regulated generating assets within ERCOT.

Focus of this IRP



4

Other than a discussion of the requirements of the FERC-approved AEP System Integration Agreement (SIA), this document will only address 2010 resource planning for the AEP-East zone. Planning for affiliates PSO and SWEPCO operating in SPP will be communicated in a separate IRP document.

1.2.1 AEP-East Zone–PJM:

AEP’s eastern zone (“AEP-East” or “AEP-PJM”) operating companies collectively serve a population of about 7.2 million (3.26 million retail customers) in a 41,000 square-mile area in parts of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia, and West Virginia. The internal (native) customer base is fairly diversified. In 2009, residential, commercial, and industrial customers accounted for 28.4%, 22.2%, and 35.9%, respectively, of AEP-East’s total internal energy requirements of 130,519 GWh. The remaining 13.5% was supplied for street and highway lighting, firm wholesale customers, and to supply line and other transmission and distribution equipment losses.

AEP-East experienced its historic peak internal demand of 22,411 MW on August 8, 2007. The historic winter peak internal demand, 22,270 MW, was experienced on January 16, 2009. AEP-East reached its all-time peak total demand of 26,467 MW, including sales to nonaffiliated power systems, on August 21, 2003.

1.2.2 AEP-East Pool

The 1951 AEP Interconnection Agreement (AEP Pool) was established to obtain efficient and coordinated expansion and operation of electric power facilities in its eastern zone. This includes the coordinated and integrated determination of load and peak demand obligations for each of the member companies. Further, member companies are expected to “rectify or alleviate” any relative capacity deficits of an extended nature to maintain an “equalization” over time. As such, capacity planning is performed on an AEP-East integrated basis, with capacity assignments made to the pool members based on their relative deficiency within the Pool.

1.2.3 AEP System Interchange Agreement (East and West)

The 2000 System Interchange Agreement (SIA) among AEPSC - as agent for the AEP-East operating companies, and Central and Southwest Services, Inc. (CSW) – including the AEP-West companies - was designed to operate as an umbrella agreement between the FERC-approved 1997 Restated and Amended CSW Operating Agreement for its western (former CSW) operating companies and the FERC-approved 1951 AEP Interconnection Agreement for its eastern operating companies. The SIA provides for the integration and coordination of AEP’s eastern and western companies’ zones. In that regard, the SIA provides for the transfer of capacity and energy between the AEP-East zone and the AEP-West zone under certain conditions. Since the inception of the SIA, AEP has continued to reserve annually, the transmission rights associated with a prescribed (up to) 250 MW of capacity from the AEP-East zone to the AEP-West zone.



5

1.3 Commodity Pricing

AEP updates its commodities forecast twice each year. The Fall of 2009 forecast (2H09 Forecast) was used as the basis for resource modeling in this IRP. After comparing the 2H09 Forecast to the subsequent long term forecast prepared in the Spring of 2010 (1H10 Forecast), as shown in Exhibit 1-3, it was apparent that the effects of the revised pricing estimates were not significant in determining future resource additions and did not warrant a new resource evaluation.

Exhibit 1-3 Comparison of 2H09 and 1H10 Commodity Forecasts

CAPP Coal 2H2009 Vs 1H2010 Reference Case

(2H09 Reference Case 2010 = 1.0)

-

1.00

2.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2H09 CAPP 1H10 CAPP


PRB Coal 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

-

1.00

2.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2H2009 1H2010


TCO Delivered Gas 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

-

1.00

2.00

3.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2H2009 1H2010


On Peak Power PJM AEP Hub - 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2010 = 1.0)

-

1.00

2.00

3.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2H2009 1H2010


CO2 Emission Costs/Tonne - 2H2009 Vs 1H2010 Reference Case (2H09 Reference Case 2014 = 1.0)

-

1.00

2.00

3.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2H2009 1H2010




6



7

2.0 Industry Issues and Their Implications

2.1 Environmental Rulemakings and Legislation

This 2010 IRP considered existing and potential U. S. Environmental Protection Agency (EPA) rulemakings as well as proposed legislation controlling CO2 emissions. Emission compliance requirements have a major influence on the consideration of supply-side resources for inclusion in the IRP because of their potential significant effects on both capital and operational costs. The cumulative cost of complying with these rules could ultimately have an impact on proposed retirement dates of any currently non-retrofitted coal and lignite units.

2.1.1 Mercury and Hazardous Air Pollutants Regulation

The Clean Air Mercury Rule (CAMR) was issued by the U.S. EPA in May 2005. The rule instituted a cap-and-trade program to limit emissions of mercury from coal-fired power plants across the United States. The CAMR required coal-fired power plants to begin monitoring mercury emissions on January 1st, 2009, with cap and trade emission reductions required beginning on January 1st, 2010. However, the CAMR was appealed by various entities, and in February 2008 the United States Court of Appeals for the District of Columbia Circuit issued a decision vacating the CAMR.

With the vacatur of CAMR and the completion of the appeals process, the U.S. EPA has announced its intent to develop a new regulatory program for mercury emissions and other Hazardous Air Pollutants, including, among others, arsenic, selenium, lead, cadmium and various acid gases (collectively “HAPs” or “HAPs rulemaking”) under the Maximum Achievable Control Technology (MACT) provision of the Clean Air Act. A MACT rule for HAPs will establish regulations that are "command and control"; meaning that it will not be a cap-and-trade program and that unit specific controls or emission rates will need to be met. The EPA has set a deadline for a proposed MACT rule to be issued for public review and comment in March 2011 and a final rule to be issued in November 2011. This rule is expected to take effect as early as December 2015. However, the MACT standards for HAPs has not been established, and the requirements for each unit will not be tentatively known until a proposed rule is issued and will not be definitively known until a final rule is issued late next year.

Although not definitively known, AEP Engineering Project and Field Services (EP&FS) and AEP Environmental Services attempted to identify reasonable proxies for MACT at each AEP coal unit. For the most part, some combination of Flue Gas Desulphurization (FGD) and Selective Catalytic Reduction (SCR), or Activated Carbon Injection (ACI) with fabric filter fugitive dust collection systems would likely be required for compliance.

2.1.2 Coal Combustion Residuals (CCR) Regulation

CCRs are the materials that result from combusting coal, and can include bottom ash, fly ash, and byproduct created from FGD systems capturing SO2 from flue gas. Currently CCRs are



8

classified as non-hazardous waste. Disposal of these materials is currently regulated at the state level. However, the U.S. EPA is developing a new regulatory program that will move regulation to the Federal level to ensure greater consistency across the country on disposal practices. A draft CCR disposal rule was issued in mid-2010. A final rule is expected in roughly a year, or mid-2011. The EPA has indicated it may regulate disposal of these materials as a special class of non-hazardous waste, or potentially as a hazardous waste. Either approach will result in more restrictive disposal requirements than currently exist.

2.1.3 Transport Rule

On July 6, 2010 the U.S. EPA proposed a Transport Rule to replace the 2005 Clean Air Interstate Rule (CAIR) which was vacated in 2008 by the U.S. Court of Appeals for the District of Columbia. The Transport Rule will require 31 states and the District of Columbia to reduce power plant emissions of sulfur dioxide (SO2) and oxides of nitrogen (NOX). The emission reductions will be state specific with limited allowance trading opportunity, and will become effective at an intermediate level in 2012, then at a final, more restrictive level in 2014. The emission reductions will be relative to a 2005 base year level. Each state will be required to develop source (plant) specific targets.

Once the Transport Rule is finalized and source specific targets are communicated, an action plan can be established to comply with this requirement. AEP’s expectation is that this rule may influence the timing of certain FGD retrofits, plant operations, and/or unit retirements. However, given that AEP must operate within a previously established New Source Review (NSR) Consent Decree “cap” for NOX and SO2, and also retrofits or retire certain units by specific dates, the incremental Transport Rule compliance measures are not expected to significantly change the resource plan established in this report.

2.1.4 New Source Review—Consent Decree.

In December, 2007 AEP entered into a settlement of outstanding litigation around NSR compliance. Under the terms of the settlement, AEP will complete its environmental retrofit program on its operated Eastern units, operate those units under a declining annual cap on total SO2 and NOX emissions and install additional control technologies at certain units. The most significant additional control projects involve installing FGD and SCR systems at nine AEP-East coal fired units (Amos 1-3, Big Sandy 2, Cardinal 1, Conesville 4, Muskingum River 5 and Rockport 1 and 2) over an 11 year period beginning in 2009.

2.1.5 Carbon and Greenhouse Gas (GHG) Legislation

The electric utility industry, as a major producer of CO2, will be significantly affected by any GHG legislation. The push towards federal climate change legislation is continuing within Congress. The Waxman-Markey “American Climate and Energy Security Act of 2009” was approved by the House of Representatives in June 2009, but was not followed up with comparable legislation being



9

approved by the U.S. Senate. In December 2009 the U. S. EPA issued a finding that GHG from industry, vehicles, and other sources represent a threat to human health and the environment. In June 2010 the Senate voted 53-47 to reject an attempt to block the U.S. EPA from imposing new limits on carbon emissions. This defeat is seen as providing momentum to climate legislation efforts. Climate change legislation currently in the U.S. Senate is being sponsored by Senators Kerry and Lieberman. In most respects this draft legislation comports with the cap-and-trade provisions of the Waxman-Markey Bill.

With climate legislation on the horizon, the Company has embarked on an initiative to advance carbon capture technology to a commercial scale. In March 2007, AEP signed agreements with world-renowned technology providers for carbon capture and storage. A “product validation facility” has been constructed at the Mountaineer Plant in West Virginia and successfully began operation in the fall of 2009.

The carbon capture and storage equipment (CCS) operating on AEP’s 1,300 MW Mountaineer Plant is a 20 MW (electric) product validation. It is designed to capture approximately 100,000 metric tons of CO2 per year over a four to five year period; the CO2 is being stored in deep geologic reservoirs. AEP now plans to scale up the Mountaineer Chilled Ammonia Process (CAP) to capture CO2 from a 235 MWe slip stream and has been awarded $336 million in funding from the U.S. Department of Energy. The expectation is for the commercial scale technology project to have a 90% capture rate of approximately 1.5 million tons of CO2 per year and be online in 2015.

Utility applications of CCS technologies continue to be developed and tested, and as such are not yet commercially available on a large scale. However, given the focus on the advancement and associated cost reduction of such technologies, it is likely to become both available and cost-effective at some point over the IRP’s longer-term planning horizon (through 2030). However, this is very dependent on the type of federal climate legislation that is passed and the degree to which there is financial support for CCS technology in such legislation. Assuming carbon capture and storage becomes commercially viable weight must be given to the options (and generating facilities) that are most readily adaptable to this technology

2.2 Additional Implications of Environmental Legislation – Unit Disposition Analysis

An AEP-East unit disposition study was undertaken by an IRP Unit Disposition evaluation team involving numerous AEP functional disciplines including: Fossil & Hydro Operations, Engineering, Project & Field Services (EP&FS), Environmental Services, Fuel Emissions Logistics (FEL), Commercial Operations, Transmission Planning, and Resource Planning. This fourth quarter 2009 effort was a follow-up to earlier studies that have been performed annually since 2005. As before, the team’s primary intent was to assess the relative composition and timing of potential unit retirements. As in previous reviews, the initial focus was on the older-vintage, less-efficient, uncontrolled coal units in the AEP-East fleet. Factors including PJM operational flexibility, emerging unit liabilities, and workforce/community factors were considered when recommending the relative profile of potential unit retirements. In this 2010 IRP cycle review the team also considered the implications of the potential (dispatch) cost impacts associated with CO2 emissions, as well as cost to comply with



10

assumed emerging HAPs and CCR rulemaking on, particularly, the relatively newer and reasonably-thermally efficient uncontrolled super-critical coal units operating in the AEP-East fleet.

For instance, according to the AEP Environmental Services group, such federal rulemaking for HAPs could become effective by as early as the end of 2015 when a “command-and-control” policy could require all U.S. coal and lignite units to install mercury and heavy metals/toxins control technologies including (combined) FGD, SCR, as well as, potentially, ACI with fabric filter emissions control equipment. New rules on the handling and disposal of CCRs could likewise be implemented as early as 2017, requiring additional investment in the coal fleet to convert “wet” fly ash and bottom ash disposal equipment and systems — including attendant landfills and ponds — to “dry” systems. The cumulative cost of complying with these rules will most certainly require additional analysis and may have an impact on proposed retirement dates of any currently non-retrofitted coal unit.

It should be noted that the conclusions of this updated unit disposition study are for the expressed purpose of performing this overall long-term IRP analysis and reflect on-going and evolving disposition assessments. From a capacity perspective, no formal decisions have been made with respect to specific timing of any such unit retirements, except as identified in the NSR Consent Decree stipulations. These disposition analyses and renderings are deemed necessary so that the prospects for any ultimate decisions can be integrated into a capacity replacement plan in a way that is ratable and practical.

2.3 Renewable Portfolio Standards

As identified in Exhibit 2-1, 29 states and the District of Columbia have set standards specifying that electric utilities generate a certain amount of electricity from renewable sources. Seven other states have established renewable energy goals. Most of these requirements take the form of “renewable portfolio standards,” or RPS, which require a certain percentage of a utility energy sales to ultimate customers come from renewable generation sources by a given date. The standards range from modest to ambitious, and definitions of renewable energy vary. Though climate change may not always be the primary motivation behind some of these standards, the use of renewable energy does deliver significant GHG reductions. For instance, Texas is expected to avoid 3.3 million tons of CO2 emissions annually with its RPS, which requires 2,000 MW of new renewable generation by 2009.

At the federal level, an RPS ranging from 10-20% was proposed for inclusion in the Energy Independence and Security Act of 2007; but the final bill as passed into law did not contain an RPS. However, a combined federal renewable energy standard (RES) and energy efficiency standard (EES) of 20% by 2020 was adopted as part of the Waxman-Markey bill passed by the House. The Senate passed out of Committee a combined 15% RES/EES by 2021 and is also considering the House legislation. However, on July 27, 2010 Senate Majority Leader Harry Reid introduced a modest package of draft energy legislation which did not include a renewable standard. Therefore, there is only a slight possibility of passage of a federal RPS in 2010, with much improved likelihood in 2011.



11

Exhibit 2-1: Renewable Standards by State

2.3.1 Implication of Renewable Portfolio Standards on the AEP-East IRP

Renewable Portfolio Standards and goals have been enacted in well over half of the states in the U.S and over two-thirds of the PJM states. Adoption of further RPS at the state level or the

Ren

ewab

le P

ort

folio

Sta

nd

ard

s

Stat

e re

new

able

por

tfol

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tand

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new

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* †Ex

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new

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s

Incl

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non

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native

res

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es

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: 1

5%

x 2

02

0*

CA

:3

3%

x 2

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NV

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5%

x 2

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5*

AZ

: 1

5%

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5

NM

: 2

0%

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0%

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co-o

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40

% x

20

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Min

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TX

: 5

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0 M

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20

15

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20%

by

2025

*

CO

: 3

0%

by 2

02

0(I

OU

s)1

0%

by

20

20

(co

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s &

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MT

: 1

5%

x 2

01

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ND

: 10

% x

201

5

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10%

x 2

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IA:

10

5 M

W

MN

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x 2

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5(X

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x 2

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3%

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NJ:

22

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1

PA

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18

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: 2

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x 2

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2

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: 2

0%

x 2

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x 2

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15%

x 2

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in r

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015



12

enactment of Federal carbon limitations and/or an RPS will impose the need for adding more renewables resulting in a significant increase in investments across the renewable resource industry.

Wind is currently one of the most viable large-scale renewable technologies and has been added to utility portfolios mainly via long-term power purchase agreements (PPA). Recently, many IOUs have begun to add wind projects to their generation portfolios. The best sites in terms of wind resource and transmission are rapidly being secured by developers. Further, while an extension of the Federal Production Tax Credit (PTC) and investment tax credits (ITC) for wind projects - to the end of 2012 - was enacted in February 2009, it may not be extended further as the implementation of federal carbon or renewable standards is expected to make unnecessary the development incentive provided by the PTC/ITC. Acquiring this renewable energy and/or the associated Renewable Energy Credit/Certificate (REC) sooner limits the risk of increased cost that comes with waiting for further legislative clarity nationally or in the AEP states, combined with the likely expiration of these federal incentives. AEP has experienced, however, that regulators in states without mandatory standards are reluctant to approve PPAs that result in increased costs to their ratepayers. By the end of 2010 AEP operating companies I&M, APCo, and AEP-Ohio (CSP & OPCo) will be receiving energy from at least 9 wind contracts and 1 solar project, with total nameplate ratings of 636 MW. Exhibit 2-2 summarizes the AEP-East Zone’s renewable plan, by operating company.



13

Exhibit 2-2: Renewable Energy Plan Through 2030


2009

075

00.

8%0

00

0.0%

00

00.

0%0

00

0.0

%0

750

0.2%

2010

027

60

2.7%

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00

2.5%

00

00.

0%0

100

00.

7%

052

60

1.6%

2011

037

60

3.6%

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2.5%

00

00.

0%20

100

441.

1%

2062

644

2.1%

2012

037

60

3.6%

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2.4%

00

00.

0%31

200

441.

8%

3172

644

2.3%

2013

(b)

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60

3.5%

020

00

3.2%

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0%41

250

442.

1%

4182

644

2.6%

2014

037

60

3.5%

035

00

5.6%

010

00

4.2%

6730

094

3.3

%67

1,12

694

3.8%

2015

037

60

3.5%

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10.2

%0

100

04.

2%94

400

944.

0%

941,

526

945.

0%20

160

376

03.

5%0

650

010

.3%

010

00

4.2%

120

650

505.

3%

120

1,77

650

5.6%

2017

037

60

3.5%

065

00

10.3

%0

100

04.

2%14

680

050

6.3

%14

61,

926

506.

0%20

180

376

03.

4%0

650

010

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010

00

4.2%

172

850

150

8.4

%17

21,

976

150

6.9%

2019

037

60

3.4%

065

00

10.4

%0

100

04.

1%19

895

015

09.

1%

198

2,07

615

07.

2%20

200

376

03.

4%0

650

010

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010

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4.1%

225

1,10

015

010

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225

2,22

615

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6%20

210

376

03.

3%0

700

011

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6.1%

256

1,10

020

011

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256

2,32

620

08.

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220

409

03.

6%0

700

011

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015

00

6.0%

301

1,16

720

011

.8%

301

2,42

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14

2.3.2 Ohio Renewable Portfolio Standards

Ohio Substitute SB 221 Alternative Energy requires that 25% of the retail energy sold in Ohio come from “Alternative Energy” sources by 2025. Alternative Energy consists of two main constituents, Advanced Energy and Renewable Energy. Advanced Energy includes distributed generation, clean-coal technology, advanced nuclear technology, advanced solid-waste conversion, plant efficiency improvements and demand-side management/energy efficiency above the levels mandated in the energy efficiency and Renewable Energy provisions. Renewable Energy includes solar (photovoltaic or thermal), wind, incremental hydro, geothermal, solid-waste decomposition, biomass, biologically-derived methane, fuel cells, and storage resources.

At least one-half of the Alternative Energy mandate must be met with renewable resources by 2025. Advanced Energy must provide the balance of the 25 percent goal not attained with Renewable Energy. There is a further sub-requirement that solar constitute at least 0.5 percent of retail sales by that date, and that at least half the renewable resources be from sites located in the State of Ohio. Compliance may be satisfied with the purchase of Renewable Energy Certificates (REC). There are annual benchmark requirements, which began in 2009, for the Renewable and Solar requirement and sub-requirement, respectively. Exhibit 2-3 shows the results of the current plan for AEP-Ohio in meeting the renewable energy requirements.

Exhibit 2-3: Ohio Renewable Energy Requirement and Plan

Pct GWh GWh Pct GWh GWh

2010 0.010% 4 0 0.50% 223 3032011 0.030% 13 26 1.00% 440 4982012 0.060% 26 37 1.50% 657 7962013 0.090% 40 48 2.00% 896 9512014 0.120% 54 76 2.50% 1,130 1,5122015 0.150% 68 104 3.50% 1,592 1,8272016 0.180% 82 132 4.50% 2,048 2,4032017 0.220% 100 160 5.50% 2,498 2,8622018 0.260% 118 188 6.50% 2,945 3,8042019 0.300% 136 216 7.50% 3,393 4,1192020 0.340% 154 245 8.50% 3,839 4,5782021 0.380% 171 278 9.50% 4,274 4,9962022 0.420% 188 326 10.50% 4,700 5,2362023 0.460% 205 326 11.50% 5,126 5,8102024 0.500% 223 374 12.50% 5,563 6,1452025 0.500% 223 374 12.50% 5,567 6,432

AEP-Ohio Renewables Requirement and Plan

Note: (2009/2010) Benchmarks (were/will be) met with both Purchased and Plan RECs

SolarBenchmark

FullYear

SolarPlan

TotalBenchmark

TotalPlan




15

2.3.3 Michigan Clean, Renewable, and Efficient Energy Act

Michigan’s “Clean, Renewable, and Efficient Energy Act” (2008 PA 295) requires that 10 percent of retail sales be met from renewable resources by the year 2015. The initial requirement is for 2012 and the percentage ramps up over the next three years as shown in Exhibit 2-4. New sources must be within Michigan or in the retail service territory of the provider, outside of Michigan. Credit is given for existing sources, such as I&M’s hydroelectric plants. Renewable Energy Credits will have a three-year life in Michigan.

Exhibit 2-4: AEP I&M-Michigan Renewable Requirement and Plan

Pct GWh GWh GWh GWh

2010 0.0% 0 0 0 02011 0.0% 0 0 0 02012 2.0% 59 70 17 882013 3.3% 99 93 17 1102014 5.0% 148 161 17 1782015 10.0% 296 293 17 3102016 10.0% 295 293 17 3102017 10.0% 295 293 17 3102018 10.0% 295 293 17 3102019 10.0% 296 293 17 3102020 10.0% 298 293 17 3102021 10.0% 299 315 17 3322022 10.0% 300 315 17 3322023 10.0% 302 315 17 3322024 10.0% 303 397 17 4142025 10.0% 305 419 17 436

I&M Michigan Renewables Requirement and Plan

RenewableBenchmark

Total Renewable Energy Plan

FullYear

ExistingHydroCredits

TotalPlan


2.3.4 Virginia Voluntary Renewable Portfolio Standard

Virginia Code section 56-585.2 creates incentives for utilities to meet voluntary renewable energy goals. The basis of the goals is energy sales in 2007 less energy provided by nuclear plants. The goals are 4% of that sales figure in 2010, 7% by 2016, 12% by 2022, and 15% by 2025. Double credit is given for energy from solar or wind projects. Including the projects in the current plan along with existing run-of-river hydroelectric plants, APCo should have sufficient credits required to meet the voluntary goals for each year of the Planning Period even though the Virginia State Corporation Commission denied the Company’s request for recovery of Virginia share of costs associated with its three most recent wind purchased power agreements totaling 201 MW (90 MW net).



16

2.3.5 West Virginia Alternative and Renewable Energy Portfolio Standard

The West Virginia Alternative and Renewable Energy Portfolio Standard act was passed in the 2009 session of the West Virginia Legislature (SB297). Since its initial passage it has been amended three separate times, once apparently by a transcription error. The act requires that as of January 1, 2015 electric utilities (an electric distribution company or electric generation supplier who sells electricity to retail customers in West Virginia) must own “credits” equal to a certain percentage of the electric energy sold to customers in West Virginia in the previous year. For 2015 to 2019 the credits must equal 10 percent of the previous year’s sales. For 2020 to 2024, the credits must equal 15 percent and after January 1, 2025 the credits must equal 25 percent. The requirements apparently sunset on June 30, 2026 as the result of a section added from one of the amendments.

Credits can be earned by either the utilization of an “alternative energy resource,” a “renewable energy resource” or the employment of an “energy efficiency or demand-side energy initiative project” or a “Greenhouse gas emission reduction or offset project.” The act carries specific definitions and sub-characterizations related to each of these categories.

2.4 Energy Efficiency Mandates

The Energy Independence and Security Act of 2007 (“EISA”) requires, among other things, a phase-in of lighting efficiency standards, appliance standards, and building codes. The increased standards will have a discernable effect on energy consumption. Additionally, mandated levels of demand reduction and/or energy efficiency attainment, subject to cost effectiveness criteria, are in place in Ohio, Indiana and Michigan in the AEP-East Zone. The Ohio standard, if cost-effective criteria are met, will result in installed energy efficiency measures equal to over 20 percent of all energy otherwise supplied by 2025. Indiana’s standard achieves installed energy efficiency reductions of 13.90% by 2020 while Michigan’s standard achieves 10.55%. Virginia has a voluntary 10% by 2020 target, while West Virginia allows energy efficiency to count towards its renewable standard. No mandate currently exists in Kentucky, however KPCo has offered DR/EE programs to customers since the mid-1990’s.

2.4.1 Implication of Efficiency Mandates: Demand Response/Energy Efficiency (DR/EE)

The AEP System (East and West zones) has internally committed to system-wide peak demand reductions of 1,000 MW by year-end 2012 and energy reductions of 2,250 GWh, approximately 60-65% of which is in the AEP-East zone. Concurrently, several states served by the AEP System have mandated levels of efficiency and demand reduction. Within the AEP-East zone, Ohio and Michigan have statutory benchmarks which took effect in 2009. As a result of the DSM generic case in Indiana, regulatory benchmarks have been put into effect beginning in 2010 for Indiana. In lieu of mandates or benchmarks, stakeholders expect realistic levels of cost-effective demand-side measures to be employed. While this IRP establishes a method for obtaining an estimate of DR/EE that is reasonable to expect for the zone, as a whole; the ratemaking process in the individual states will ultimately shape the amount and timing of DR/EE investment.



17

2.4.2 Ohio Energy Efficiency Requirements

Energy Efficiency must produce prescribed reductions in energy usage that cumulatively add to 22.2 percent of annual retail energy sold by the year 2025. Additionally, peak demand must be reduced 7.75 percent by 2018. Annual Energy Efficiency and Demand Response benchmark goals have been in-place since 2009.

2.4.3 Transmission and Distribution Efficiencies

The IRP also takes into account other technology initiatives designed to improve the efficiency of the AEP energy delivery and distribution systems. These initiatives include the demonstration of technologies for more effective integrated volt/var controls (IVVC) and community energy storage on the distribution system (CES) that would reduce customer usage, as well as advanced transmission infrastructure technologies to reduce energy losses within the energy delivery system. The transmission and distribution technology programs are designed to avoid or defer the need for infrastructure and reduce emissions by avoiding energy usage and energy lost in the transmission and distribution of energy to ultimate AEP customers.

2.5 Issues Summary

The increasing number of variables and their uncertainty has added to the complexity of producing an integrated resource plan. No longer are the variables merely the cost to build and operate the generation, a forecast of what had traditionally been stable fuel prices and growth in demand over time. Volatile fuel prices and uncertainty surrounding the economy and environmental legislation require that the process used to determine the traditional “supply and demand” elements of a resource plan is sufficiently flexible to incorporate more subjective criteria. The introduction of a cap-and-trade system around CO2 and high capital construction costs weigh unfavorably on solid-fuel options, but conclusions must be metered with the knowledge that there is a great deal of uncertainty.

One way of dealing with uncertainty is to maintain optionality. That is, if there exists the potential for very expensive carbon legislation, one might favor a solution that minimizes carbon emissions, even if that solution is not the least expensive. Likewise, while there may not yet be a national RPS, procuring or adding wind generation resources now will put a company ahead of the game if one does come to pass. In this way, the company is trading future uncertainty for a known cost. Lastly, adding diversity to the generating portfolio reduces the risk of the overall portfolio. That may not be the least expensive option in a “base” (or most probable) case, but it minimizes exposure to adverse future events and could reduce the ultimate cost of compliance if the resultant demand for renewable resources continues to grow, outpacing the supplier resource base.



18



19

3.0 Current Supply Resources

The initial step in the IRP process is the demonstration of the region-specific capacity resource requirements. This “needs” assessment must consider projections of:

Existing capacity resources—current levels and anticipated changes

Changes in capability due to efficiency and/or environmental retrofit projects

Changes resulting from decisions surrounding unit disposition evaluations

Regional capacity and transmission constraints/limitations

Load and (peak) demand (see Section 4.2)

Current DR/EE impacts (see Section 4.3)

RTO-specific capacity reserve margin criteria (see Section 5.1)

In addition to the establishment of the absolute annual capacity position, an additional “need” to be discussed in this section will be a determination of the specific operational expectation (duty type) of generating capacity–baseload vs. intermediate vs. peaking.

3.1 Existing AEP Generation Resources

Exhibit 3-1 offers a summary of all supply resources for the AEP-East zone (with detail appearing in Appendix A). The current (June 1, 2010) AEP-East summer supply of 27,810 MW is composed of the following resource components (the coal resources include AEP’s share of OVEC):

Exhibit 3-1: AEP-East Capacity (Summer) as of June 2010

Summer Rating PJM UCAPMW % of Total MW MW

Coal 22,385 77% 22,152 22,136Nuclear 2,115 7% 2,029 2,029Hydro 745 3% 680 948

Gas/Diesel 3,186 11% 2,865 3,256Wind 718 2% 80 48Solar 10 0% 4 0Total 29,159 100% 27,810 28,417

Nameplate (Winter) RatingSupply Resource Type


3.2 Capacity Impacts of Generation Efficiency Projects

As detailed in Appendix B, the capability forecast of the existing AEP-East generating fleet reflects several unit up-ratings over the IRP period, largely associated with various turbine efficiency upgrade projects planned by AEP-EP&FS for selected 1,300 and 800 MW-series coal-steam turbine generating units. Additionally, AEP continues to work towards improving heat rates of its generating fleet. Such improvements, while not necessarily increasing capacity, do improve fuel efficiency.



20

3.2.1 D. C. Cook Nuclear Plant (Cook) Extended Power Uprating (EPU)

A change which is not included in Appendix B but which is reflected in the 2010 Plan is a strategic project that will increase the generating capability of Cook Units 1 and 2. Implemented in conjunction with a series of plant modifications tied to NRC relicensing requirements to improve design and operating margins and to address component aging issues, a net capacity increase of more than 400 MWe from the two units appears technically and economically achievable. Three interrelated issues challenge the continued economic performance of Cook:

1. Design and operating margins of some systems, structures, and components (SSCs) are lower than desirable and should be enhanced to support improved operational flexibility and satisfy regulatory expectations.

2. Many SSCs will reach end-of-life prior to expiration of the extended Nuclear Regulatory Commission plant license and need to be replaced to maintain margins and allow continued plant operation.

3. The Nuclear Steam Supply Systems for Cook-1 and Cook-2 were designed and built with substantial conservatism to allow uprating, but with the exception of minor Margin Recovery Uprating of about 1.7% performed on each unit, this conservatism remains largely untapped.

Consequently, the Cook Plant does not produce its maximum potential cost-effective electrical output. License changes and modification of selected systems and components could increase the capacity of both units and effectively decrease ongoing plant production costs. However, if not properly implemented, the analyses and modifications needed for uprating could introduce performance or reliability concerns that would negate the value of the capacity increase. The problem to be addressed by the EPU Project is to integrate necessary margin improvement and on-going life cycle management efforts with an uprating for each Cook unit to the maximum safe and reliable reactor thermal power achievable while demonstrating and achieving cost justification of uprating on a life-cycle basis.

A break even analysis performed using the Strategist resource optimization model shows that the EPU Project is economical even at costs significantly exceeding the current preliminary estimates and as such has been “embedded” in this 2010 IRP.

3.3 Capacity Impacts of Environmental Compliance Plan

As also detailed in Appendix B, the capability forecast of the existing generating fleet reflects several unit de-ratings associated with environmental retrofits (largely scrubbers or CCS) over the IRP period. The net impact to existing units as a result of the planned up-ratings and de-ratings is reflected in that appendix.



21

3.4 Existing Unit Disposition

Another important initial process within this IRP cycle was the establishment of a long-term view of disposition alternatives facing older coal-steam units in the east region. The Existing Unit Disposition identified 13 sets of aging AEP-East zone generating assets consisting of a total of 26 units with a summer rating of 5,343 MW.

Big Sandy Unit 1 (273 MW) KPCo

Conesville Unit 3 (165 MW) CSP

Clinch River Units 1-3 (690 MW) APCo

Glen Lyn Unit 5 (90 MW) APCo

Glen Lyn Unit 6 (235 MW) APCo

Kammer Units 1-3 (600 MW) OPCo

Kanawha River Units 1 & 2 (400 MW) APCo

Muskingum River Units 1 & 3 (395 MW) OPCo

Muskingum River Units 2 & 4 (395 MW) OPCo

Picway Unit 5 (95 MW) CSP

Sporn Units 1-4 (580 MW) APCo (Units 1 & 3), OPCo (Units 2 & 4)

Sporn Unit 5 (440 MW) OPCo

Tanners Creek Units 1-4 (985 MW) I&M

Among this group of units are several that were impacted by the Consent Decree from the settled New Source Review litigation. These units, and the dates by which, according to the agreement, they must be retired, repowered, or retrofitted (R/R/R) with FGD and SCR systems, are:

Conesville Unit 3, by December 31, 2012 Muskingum River Units 1-4, by December 31, 2015 Sporn Unit 5, by December 31, 2013 A total of 600 MW from Sporn 1-4, Clinch River 1-3, Tanners Creek 1-3, or Kammer 1-3, by

December 31, 2018.

In order to develop a comprehensive assessment of potential unit disposition recommendations, a team encompassing multiple functional disciplines (engineering, operations, fuels, environmental, and commercial operations) also sought to confirm or challenge the preliminary economic findings by examining additional factors relevant to the units’ unique physical characteristics. A decision matrix was employed to assist in that assessment. Relative scores were constructed for each unit under the established criteria. Such scores were based on the analysis and professional judgment surrounding each unit’s known (or anticipated) infrastructure liabilities, operational flexibility capabilities in PJM, as well as work force and socioeconomic impacts.



22

3.4.1 Findings and Recommendations—AEP-East Units

The Unit Disposition Working Group findings are summarized here and in Exhibit 3-2. Given the size (over 5,000 MW) of the group of AEP-East units “fully exposed” to future emission expenses for CO2, possible new mercury/hazardous air pollutant and coal combustion residuals (CCR) rulemakings, it is practical to begin a stepped approach to their disposition–thus avoiding the need to build and finance multiple replacement facilities simultaneously.

Recognize that the retirement date represents the year that the unit is projected to no longer provide firm capacity value in PJM, however it still may provide energy value and therefore operate well beyond the planned capacity retirement date.

The initial unit retirements include only those R/R/R units designated in the NSR Consent Decree. Through 2014 this includes Sporn 5, 440 MW, retiring in 2010 (R/R/R date 2013); Conesville 3, 165 MW (R/R/R date 2012) and Muskingum River 2 & 4, 395 MW (R/R/R date 2015) retiring in 2012; and Muskingum River 1 & 3, 395 MW (R/R/R date 2015), with a potential retirement date of 2014.

The remaining “fully exposed” units are projected to retire between 2015 and 2019, assuming a staggered implementation schedule for any HAPs/Mercury/CCR regulations that may be imposed on a unit specific basis.



23

Exhibit 3-2: AEP East Fully Exposed Unit Disposition/Retirement Profile


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24

In addition, certain larger, supercritical coal units which are considered “partially exposed” to these same potential regulations due to their lack of specific environmental control equipment were also evaluated for possible retirement. These units include:

Big Sandy Unit 2 (800 MW, summer rating) KPCo - requires FGD by 2015

Muskingum River Unit 5 (600 MW) OPCo – requires FGD by 2015

Rockport Units 1and 2 (2610 MW) I&M/KPCo – requires FGD/SCR by 2017 (Unit 1)/2019 (Unit 2)

Conesville Units 5 and 6 (CSP) (790 MW) – requires SCR by 2019

The Resource Planning group analyzed, under two pricing scenarios, various options for each unit including retrofitting, retiring, or converting to gas. With the exception of Muskingum River 5, the decision to retrofit with the required controls represents the lowest cost for AEP-East customers. (See Exhibit 3-3) As with all long range planning assumptions, the decision to retrofit or retire these partially exposed units will be revisited in subsequent IRPs. As rules surrounding HAPS, CCR, and the Transport Rule are finalized, more certainty with regard to the timing and magnitude of incremental capital investments to comply with these regulations will certainly factor into the retrofit/retire decision making process. Given FGD construction lead times and the NSR Consent Decree stipulations, a final decision on Muskingum River 5 and Big Sandy 2 will be required before the end of 2011.



25

Exhibit 3-3: Partially Exposed Unit Disposition Profile


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26

3.4.2 Extended Start-Up

As part of AEP’s continuing effort to manage operating and maintenance expenses, AEP-East launched a plan to place 10 generating units - representing 1,925 megawatts (MW) of capacity - in “extended startup” status for nine months of the year. This action includes the 450-MW Unit 5 at the Sporn Plant. AEP had announced plans to mothball Sporn 5 in April of 2009, noting that the unit has no PJM capacity obligations in 2010. Because Sporn 5 has no PJM capacity obligation, it will be the only unit to operate in the four-day “extended startup” mode year-round.

The plan, which took effect June 1, 2010 allows the company to re-deploy and maximize the productivity of employees at several coal-fired units that are projected to run less frequently over the next few years.

The units that will be placed in extended startup status are:

Picway Unit 5, 95 MW, CSP;

Muskingum River Unit 4, 215 MW, OPCo;

Clinch River Unit 3, 235 MW, APCo.;

Tanners Creek Units 1 & 2, 290 MW, I&M.;

Glen Lyn Units 5 & 6, 335 MW, APCo;

Sporn Units 3, 4 & 5, 750 MW, APCO (Unit 3), OPCO (Units 4&5); and

In extended startup mode, the affected units will remain off line until needed to meet demand. When needed, plant staff will be able to start the affected units during a window of four days during the nine non-peak months of the year. In addition, Kammer Units 1-3 (OPCo) are now in a “substitute operation” mode, where only two units will be staffed and operating at any one time.

3.4.3 Implications of Retirements on Black Start Plan

The eventual retirement of Conesville 3, and in time other units such as the Muskingum River and Tanners Creek units, will have implications for the System’s plans for black-start capability and Automatic Load Rejection, which are needed to restore the system following a transmission system collapse. In addition, PJM rules for the provision of black-start service and NERC Standards regarding the maintenance of a system restoration plan have implications on the planning, timing, announcement, etc. of the unit retirements. The AEP Generation, Transmission, and Commercial Operations groups have studied this issue and developed a list of recommended system restoration options. As the highest priority option, AEP generation engineering and Conesville plant management are completing control modifications and a test program to provide automatic load rejection capability for Conesville 5 and 6.



27

3.4.4 Applicable PJM Rules

Black start resources maintain a rolling two-year commitment to PJM. The PJM tariff therefore requires up to two years’ advance notice of retirement.

If PJM and the Transmission Owner determine there is a need to replace the deactivating black start resource, PJM will seek replacement of the retiring resource as follows:

1) PJM will post on-line a notification about the need for a new black start resource along with the location and capability requirements.

2) This posting opens a market window which will last 90 calendar days.

3) PJM will review each pending Generation Interconnection request, each new interconnection request in the market window, and each proposal from a black start unit to evaluate whether any project could meet the black start replacement criteria.

4) The Transmission Owner will have the option of negotiating a cost-based, bilateral contract in accordance with the existing process outlined in Schedule 6A of the OATT. The Transmission Owner may provide an alternative as one of the bids that will be evaluated by PJM pending FERC approval.

5) If PJM and the Transmission Owner determine more than one of the proposed projects meets the replacement criteria, the most cost-effective source will be chosen.

6) If no projects are received during the 90-day market window, PJM and the Transmission Owner will revisit the definition of the location and capability requirements, to allow more resources to become viable, even if sub-optimal.

After PJM and the Transmission Owner identify the most cost-effective replacement resource, PJM and the Transmission Owner will coordinate with the Generation Owner for the their acceptance under the PJM tariff as a black start unit.

The black start resource will be compensated for provision of black start service in accordance with the existing process in the PJM tariff.

3.4.5 AEP’s Required Actions and Options

If AEP retires Conesville 3 in 2012, PJM must be notified in 2010. PJM will require the Conesville 3 black-start capability to be replaced and the Conesville 5 and 6 control system modifications are expected to provide for automatic load rejection capability for those units. If the Conesville 5 and 6 tests are successfully completed this fall, it is expected that Conesville 5 and 6 will be automatic load reject capable and can replace and/or augment the service previously provided by Conesville 3. Accordingly, AEP Generation is coordinating with AEP Transmission Operations to update the System Emergency Operations Plan to take this capability into account after the control modifications are successfully tested by year-end 2010.

AEP and its customers will pay for the black-start service, either by providing the service or by purchasing it. AEP will continue to improve and enhance its System Emergency Restoration plans to ensure compliance with all applicable NERC Standard protocols.



28

3.5 AEP Eastern Transmission Overview

3.5.1 Transmission System Overview

The eastern Transmission System (eastern zone) consists of the transmission facilities of the seven eastern AEP operating companies. This portion of the Transmission System is composed of approximately 15,000 miles of circuitry operating at or above 100 kV. The eastern zone includes over 2,100 miles of 765 kV overlaying 3,800 miles of 345 kV and over 8,800 miles of 138 kV. This expansive system allows AEP to economically and reliably deliver electric power to approximately 24,200 MW of customer demand connected to the eastern Transmission System that takes transmission service under the PJM open access transmission tariff.

The eastern Transmission System is the most integrated transmission system in the Eastern Interconnection and is directly connected to 18 neighboring transmission systems at 130 interconnection points, of which 49 are at or above 345 kV. These interconnections provide an electric pathway to facilitate access to off-system resources and serve as a delivery mechanism to adjacent companies. The entire eastern Transmission System is located within the ReliabilityFirst (RFC) Regional Entity. On October 1, 2004, AEP’s eastern zone joined the PJM Regional Transmission Organization, and has been participating in the PJM markets (see Exhibit 3-4).

Exhibit 3-4: AEP-PJM Zones and Associated Companies

Source: www.pjm.com

3.5.2 Current System Issues

As a result of the eastern Transmission System’s geographical location and expanse as well as its numerous interconnections, the eastern Transmission System can be influenced by both internal and external factors. Facility outages, load changes, or generation redispatch on neighboring companies’ systems, in combination with power transactions across the interconnected network, can



29

affect power flows on AEP’s transmission facilities. As a result, the eastern Transmission System is designed and operated to perform adequately even with the outage of its most critical transmission elements or the unavailability of generation. The eastern Transmission System conforms to the NERC Reliability Standards, the applicable RFC standards and performance criteria, and AEP’s planning criteria.

AEP’s eastern Transmission System assets are aging and some station equipment is obsolete. Therefore, in order to maintain acceptable levels of reliability, significant investments will have to be made over the next ten years to proactively replace the most critical aging and obsolete equipment and transmission lines.

3.5.3 PJM RTO Recent Bulk Transmission Improvements

Despite the robust nature of the eastern Transmission System, certain outages coupled with extreme weather conditions and/or power-transfer conditions can potentially stress the system beyond acceptable limits. The most significant transmission enhancement to the eastern AEP Transmission System over the last few years was completed in 2006. This was the construction of a 90-mile 765 kV transmission line from Wyoming Station in West Virginia to Jacksons Ferry Station in Virginia. In addition, EHV/138 kV transformer capacity has been increased at various stations across the eastern Transmission System.

3.5.4 Impacts of Generation Changes:

Over the years, AEP, and now PJM, entered into numerous study agreements to assess the impact of the connection of potential merchant generation to the eastern Transmission System. Currently, there is more than 28,000 MW of AEP generation and over 6,000 MW of additional merchant generation connected to its eastern Transmission System. AEP, in conjunction with PJM, has interconnection agreements in the AEP service territory with several merchant plant developers for additional generation to be connected to the eastern Transmission System over the next several years. There are also significant amounts of wind generation under study for potential interconnection.

The integration of the merchant generation now connected to the eastern Transmission System required incremental transmission system upgrades, such as installation of larger capacity transformers and circuit breaker replacements. None of these merchant facilities required major transmission upgrades that significantly increased the capacity of the transmission network. Other transmission system enhancements will be required to match general load growth and allow the connection of large load customers and any other generation facilities. In addition, transmission modifications may be required to address changes in power flow patterns and changes in local voltage profiles resulting from operation of the PJM and MISO markets.

The retirement of Conesville units 1 and 2 in 2006 and the potential retirement of Conesville Unit 3 in 2012 will result in the need for power to be transmitted over a longer distance into the Columbus metro area. In addition, these retirements will result in the loss of dynamic voltage



30

regulation. Since there is very little baseload generation in central Ohio, the impact of these retirements could be significant. The retirement of these units requires the addition of dynamic reactive compensation such as a Static VAR Compensator (SVC) device, which will be added within the Columbus metro area in 2012.

Within the eastern Transmission System, there are two areas in particular that could require significant transmission enhancements to allow the reliable integration of large generation facilities:

Southern Indiana—there are limited transmission facilities in southern Indiana relative to the AEP generation resources, and generation resources of others in the area. Significant generation additions to AEP’s transmission facilities (or connection to neighbor’s facilities) will likely require significant transmission enhancements, including Extra-High Voltage (EHV) line construction, to address thermal and stability constraints. The Joint Venture Pioneer Project would address many of these concerns.

Megawatt Valley—the Gavin/Amos/Mountaineer/Flatlick area currently has stability limitations during multiple transmission outages. Multiple overlapping transmission outages will require the reduction of generation levels in this area to ensure continued reliable transmission operation, although such conditions are expected to occur infrequently. Significant generation resource additions in the Gavin/Amos/Mountaineer/Flatlick area will also influence these stability constraints, requiring transmission enhancements–possibly including the construction of EHV lines and/or the addition of multiple large transformers–to more fully integrate the transmission facilities in this generation-rich area. Thermal constraints will also need to be addressed. The Potomac-Appalachian Transmission Highline (PATH) project, which consists of a 765-kilovolt transmission line extending some 276 miles from the Amos Substation in Putnam County, W.Va., to the proposed Kemptown Substation in Frederick County, Maryland, will partially mitigate these constraints.

Furthermore, even in areas where the transmission system is robust, care must be taken in siting large new generating plants in order to avoid local transmission loading problems and excessive fault duty levels.



31

4.0 Demand Projections

4.1 Load and Demand Forecast Process Overview

One of the most critical underpinnings of the IRP process is the projection of anticipated resource “needs,” which, in turn, centers on the long-term forecast of load and (peak) demand. The AEP-East internal long-term load and peak demand forecasts were based on the AEP Economic Forecasting group’s load forecast completed in April 2010. AEP Economic Forecasting utilizes a collaborative process to develop load forecasts. Customer representatives and other operating company personnel routinely provide input on customers (large customers in particular) and local economic conditions. Taking this input into account, the AEP Economic Forecasting group analyzes data, develops and utilizes economic and load forecast data and models, and computes load forecasts. Economic Forecasting and operating company management team members review and discuss the analytical results. The groups work together to obtain the final forecast results. The forecast incorporates the effects of energy policy on both a state and federal level such as the 2009 American Reinvestment and Recovery Act (ARRA), Energy Independence and Security Act of 2007 (EISA) as well as load/price elasticity associated with policy impacts on the price of electricity.

The electric energy and demand forecast process involves three specific forecast model processes, as identified in Exhibit 4-1.

Exhibit 4-1: Load and Demand Forecast Process—Sequential Steps

Source: AEP Economic Forecasting

The first process models the consumption of electricity at the aggregated customer level: Residential, Commercial, Industrial, Other Ultimate customers, and Municipals and Cooperatives. It involves modeling both the short- and long-term sales. The second process contains models that

1. Monthly Sales Forecast(by FERC Revenue Classes)

Short & Long Term

2. Hourly Demand Models(Load Shapes / Losses)

3. Net Internal Energy Requirements& Demand Forecast

Load & Demand Forecast Process – Sequential Steps



32

derive hourly load estimates from blended short- and long-term sales, estimates of energy losses for distribution and transmission, and class and end-use load shapes. The aggregate revenue class sales and energy losses is generally called “net internal energy requirements.” The third process reconciles historical net internal energy requirements and seasonal peak demands through a load factor analysis which results in the load forecast.

The long-term forecasts are developed using a combination of econometric models to project load for the Industrial, Other Ultimate and Municipal and Cooperative customer classes, as well as, under proprietary license by Itron Inc., Statistically-Adjusted End-use (SAE) models for the modeling of Residential and Commercial classes.

The long-term process starts with an economic forecast provided, under proprietary license, by Moody’s Economy.com for the United States as a whole, each state, and regions within each state. These forecasts include projections of employment, population, and other demographic and financial variables for both the U.S. as a whole and for specific AEP service territories. The long-term forecasting process incorporates these economic projections and other inputs to produce a forecast of kilowatt-hour (kWh) sales. Other inputs include regional and national economic and demographic conditions, energy prices, appliance saturations, weather data, and customer-specific information.

The AEP Economic Forecasting department uses Statistically Adjusted End-use (SAE) models for forecasting long-term Residential and Commercial kWh energy sales. SAE models are econometric models with end-use features included to specifically account for energy efficiency impacts, such as those included in the Energy Policy Act of 2005 (EPAct 2005), the Energy Independence and Security Act of 2007 (EISA), and the 2009 American Reinvestment and Recovery Act (ARRA),. SAE models start with the construction of structured end-use variables that embody end-use trends, including equipment saturation levels and efficiency. Factors are also included to account for changes in energy prices, household size, home size, income, and weather conditions. Regression models are used to estimate the relationship between observed customer usage and the structured end-use variables. The result is a model that has implicit end-use structure, but is econometric in its model-fitting technique. The SAE approach explicitly accounts for energy efficiency which has served to slightly lower the forecast of Residential and Commercial class demand and energy in the forecast horizon particularly reflecting the manifestation of energy policy impacts.

AEP uses processes that take advantage of the relative strengths of both the short and long term methods. The regression models typically used in the shorter-term modeling employ the latest available sales and weather information to represent the variation in sales on a monthly basis for short-term applications. While these models generally produce accurate forecasts in the short run, without specific ties to economic factors they are less capable of capturing the structural trends in electricity consumption that are important for longer-term planning. The long-term modeling process, with its explicit ties to economic and demographic factors, is appropriate for longer-term decisions and the establishment of the most likely, or base case, load and demand over the forecast period. By overlaying these respective method outputs, AEP Economic Forecasting effectively applies the strengths of both load-modeling approaches.



33

4.2 Peak Demand Forecasts

Exhibit 4-2 reflects the AEP Economic Forecasting Group’s forecast of annual peak demand for the AEP-East zone, utilized in this IRP.

Specifically, Exhibit 4-2 identifies the AEP-East region’s internal demand profile as having 0.27% Compound Annual Growth Rate (CAGR) including the impacts of projected (embedded) Demand Response/DSM which will be discussed later in this document. This equates to a 56 MW per year increase over the 10-year IRP period through 2020 if the load growth was steady. As the graph shows, the impact of the existing recession depresses peak demand in 2010 and 2011 with a gradual increase in 2012 and 2013 from the assumed economic recovery. In addition, the chart indicates a 0.24% rate of growth, reflective of forecasted DSM/energy efficiency impacts, for internal energy sales over the 10-year period.

Exhibit 4-2: AEP-East Peak Demand and Energy Projection

118,000

119,000

120,000

121,000

122,000

123,000

124,000

125,000

126,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Net

En

erg

y R

equ

irem

ent

(GW

h)

20,400

20,600

20,800

21,000

21,200

21,400

21,600

21,800

22,000

Peak

Dem

an

d (

MW

)

Energy Peak Demand


Exhibits 4-3 and 4-4 show the current demand and energy forecasts, respectively, compared to

historical actual data and recent forecasts. Note that for both demand and energy, the current forecast

is significantly lower as recessionary impacts on demand are being reflected. The impact of future

DSM programs has been excluded from the two peak forecasts to make them comparable.



34

Exhibit 4-3: AEP-East Peak Actual and Forecast (Excludes DSM)

AEP-East RegionHistorical and Forecasted SUMMER Peak Demand (MW)

14,000

15,000

16,000

17,000

18,000

19,000

20,000

21,000

22,000

23,000

24,000

25,000

26,000

27,000

28,000

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

MW

Pea

k D

eman

d

As Reported Actual

Weather & Curtailment-Adjusted Actual

Apr 2009 Fcst (2009 IRP Basis)

Apr 2010 Fcst (2010 IRP Basis)

"Weather-Adjusted" ACTUAL CAGRs: 1989-2009 (20-Yrs) @... 1.10% 1989-1999 (10-Yrs) @... 1.59% 1999-2009 (10-Yrs) @... 0.62% 2004-2009 (5-Yrs) @... 0.16%

FORECAST CAGRs: "Apr 2009" Fcst (2009 IRP Basis)... 2010-2030 (20-Yrs) @... 1.12% 2010-2020 (10-Yrs) @... 1.36% "Apr 2010" Fcst (2010 IRP Basis)... 2010-2030 (20-Yrs) @... 0.73% 2010-2020 (10-Yrs) @... 0.71%


Exhibit 4-4: AEP-East Internal Energy Actual and Forecast

90,000

95,000

100,000

105,000

110,000

115,000

120,000

125,000

130,000

135,000

140,000

145,000

150,000

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

2015

2017

2019

Inte

rnal E

nerg

y (G

Wh)

Actual

Weather Adjusted

Nov 2008 Fcst

May 2009 Fcst

April 2010 Fcst

Used in the current 2010 IRP




35

4.2.1 Load Forecast Drivers

It is critical to note some of the major assumptions driving these demand profiles for the eastern (AEP-PJM) zone:

1) As set forth earlier in this report, it has been assumed for purposes of this IRP cycle that AEP’s Ohio operating company legal entities, OPCo and CSP, will continue to plan to serve those retail load obligations for which they have had an historical obligation to serve, beyond the current end of the period set forth under the approved AEP-Ohio Electric Security Plan (ESP) that expires at the end of 2011.

2) The assumption that the load to serve a major industrial load operating six aluminum potlines at its facilities– would continue at the current existing level of approximately 60% of its full capacity (approximately 4 potlines). Two other large industrial customers are assumed to remain idle in the forecast.

3) Any major wholesale load obligations (largely, municipalities and cooperatives who currently have or have had a relationship with AEP as a “FERC tariff” customer) assumed to be renewed or extended over the planning period under long-term contracts. However, an observation from the underlying data to support Exhibit 4-2 is that such firm or “committed” wholesale demand projections are relatively constant over the LT forecast period and, in total, represent a small percentage (< 10%) of the east region’s overall load obligation.

4) Additionally, as described below, this forecast incorporates the effects of all current DR/EE program offerings and targets mandated by state commissions. The DR/EE legislative and regulatory mandated goals in Indiana, Michigan and Ohio are very aggressive, yet assumed achievable in the load forecast. It also includes energy efficiency and peak demand reduction that “occurs naturally” as a function of shifting consumer behavior. Consumer-driven, naturally-occurring DR/EE has a significant impact on energy consumption.

5) Finally this forecast incorporates the net effects of Price Elasticity (described below). In so doing the forecast attempts to predict the load reduction that occurs as a result of a shift in consumer behavior as a reaction to price fluctuations.

The impacts from energy policy such as EISA and ARRA are expected to be reflected on the demand side. These will predominately come through increased lighting, appliance, and building efficiency standards and codes. The efficiency of lighting is set to increase by 20-30% by 2012-24. Efficiency standards for appliance equipment including residential boilers, clothes washers and dishwashers are also set to increase through 2014. Efforts to promote energy efficiency in commercial buildings as well as in industrial energy use are expected as well. Section 7 of this document details the impacts from the DSM programs that are currently offered as well as program impacts estimated in future years

The economic impacts of a carbon dioxide cap regime will be wide reaching and impact electricity demand through market adjustments in various sectors. As an early attempt to quantify some type of initial impact, a price elasticity effect on demand has been embedded in the load



36

forecast. The timing and impact of this scenario is truly speculative, and represents only one of many possible policy actions.

As mentioned above, one of the drivers of the load forecast deals with price elasticity. An

example of a completely inelastic good is one that consumers cannot or will not change their

consumption of in response to changes in the price of the product. In the short term, most consumers

can make minimal changes to their electricity consumption behavior, so electricity is one example of

a fairly inelastic good. The exception is energy intensive industrial sectors, where companies can

shift production to other facilities, close facilities, switch fuels or change capital equipment.

Changing large energy using equipment (A/C, furnace, etc) for most consumers is a long-term

decision. To make a truly informed decision, any price differential between the competing fuels must

be known to be sustainable for consumers to take the financial risk. The long-term nature of these

decisions makes electricity (or natural gas) even less price elastic in the long-term. Since consumers

have limited options for change, price changes are very significant and become even more so during

stressful economic periods.

Over the last 4 to 6 years, the price of electricity has increased significantly. In real terms

(adjusting for inflation), the price increases reverse a long-term trend of prices declining over

previous decades. In response, the growth in electricity consumption has been dampened with the

increased prices. In an industry with sales growth around 1% per year, even a product with a low

price response (elasticity) will see an impact. For example, using 1% load growth with no price

changes and an overall own-price elasticity of -0.15, a long-term doubling of price, 100% increase,

will result in a 15% decrease in consumption. Over a 15 year period, 1% load growth would be

reduced to no load growth. Therefore, the expected costs of achieving environmental, renewable and

energy efficiency goals for the company will continue to increase the burden on the consumer and

thus reduced load growth going forward.



37

5.0 Capacity Needs Assessment

Based on the assessment of AEP-East’s current resources as described in Section 3, and its energy and peak demand projections as discussed in Section 4, a capacity needs assessment can be established that will determine the amount, timing and type of resources required for this 2010 IRP Cycle.

The 2010 AEP-East load forecast as updated in April, 2010, accounts for:

1) AEP-East region’s internal demand profile as having 0.27% CAGR (or 0.71 when projected, embedded DSM is excluded). This equates to 56 MW per year increase (or 152 MW when DSM is excluded) over the 10-year IRP period through 2020 if the load growth was steady.

2) A major industrial customer will operate at 60% load;

3) 1,119 MW of peak demand reduction due to interruptible loads and Advanced Time of Day pricing by 2020.

The forecast of AEP-East capability additions/subtractions reflected through the ten years 2011 through 2020:

1) the potential retirement of 2,300 MW of coal fired capacity by 2015 and up to 6,000 MW by 2020;

2) 199 MW of plant derates associated with environmental and biomass retrofits partially offset by plant efficiency and other improvements of 73 MW.

5.1 PJM Planning Constructs - Reliability Pricing Model (RPM)

Effective with its 2007/08 delivery year (June 1, 2007 through May 31, 2008), PJM instituted the RPM capacity-planning regime. Its purpose is to develop a long-term price signal for capacity resources as well as load-serving entity (LSE) obligations that is intended to encourage the construction of new generating capacity in the region. The heart of the RPM is a series of capacity auctions, extending out four planning years, into which all generation that will serve load in PJM will be offered. The required reserve margin under RPM is determined by the intersection of the capacity-offer curve with an administratively-drawn demand curve. In steady-state mode, the auction will be held 38 months before the beginning of the plan year, with subsequent incremental auctions to trim up the capacity commitments as capacity commitments, unit reliability/contribution and demand forecasts change.

FERC has authorized, and PJM has provided for an alternative to the capacity auction, called the Fixed Resource Requirement (FRR), which may be appropriate for vertically integrated utilities to use. Under the FRR, the reserve margin is not dependent upon the intersection of the offer curve and the administratively-set demand curve but is built directly upon the fixed PJM Installed Reserve Margin (IRM) requirement as it was prior to the introduction of RPM. This alternative allows opting entities to meet their requirements with a lower capacity requirement than might have resulted under the auction model and with more cost certainty. AEP has previously elected to “opt-out” of the RPM (auction) and has been utilizing the FRR (self-planning) construct. That opt-out of the PJM capacity auction currently is effective through the 2013/14 delivery year, for which the auction was held in



38

May, 2010. AEP will determine for each subsequent year whether to continue to utilize FRR for an additional year or to “opt-in” to the RPM auction for a minimum five-year commitment period.

5.2 PJM Going In Forecast and Resources

The demand and resource figures include impacts of existing and approved state/jurisdictional DR/EE programs and existing PPAs for renewable resources. They also include the addition of the 540 MW Dresden combined cycle facility currently under construction. They do not consider new DR/EE programs that were evaluated as part of this year’s IRP process or additional renewable resources needed to meet the System’s stated goals. The resultant capacity gap arises in the 2018 timeframe and grows in future years, primarily with projected unit retirements.

The forecast considers PJM minimum reserve requirements under PJM’s self-planning Fixed Resource Requirements (FRR) capacity alternative and estimated Equivalent Demand Forced Outage Rates (EFORd) of AEP generators.

Exhibit 5-1 offers the “going-in” capacity need of the AEP-East zone prior to uncommitted capacity additions. It amplifies that the region’s overall capacity need does not occur until the end of the Planning Period (2018-2019). “Committed” new capacity includes completion of the 540 MW Dresden combined cycle facility in 2013, the assumed performance of the Donald C. Cook Nuclear Plant Extended Power Uprate (EPU) project, and assumed execution of purchase power agreements for renewable energy (largely, wind) resources.

Exhibit 5-1: Summary of Capacity vs. PJM Minimum Required Reserves

AEP-East

"Going-In" PJM Capacity (UCAP) Position

NO CAPACITY ADDITIONS (Post-Dresden and Cook EPU)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

32,000

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

PJM Planning Year (Eff: 6/1/XXXX)

MW

Cumul Retirements (5930 MW by 2019-20 PY)

Cook EPU (2014-18)

Dresden (2013)

UCAP w/o New Additions






39

The going-in capacity forecast considered the potential retirement of close to 6,000 MW of largely older, less-efficient coal-fired units over the Planning Period due largely to external factors including known or anticipated environmental initiative from the U.S. Environmental Protection Agency (EPA), as well as the December 2007 stipulated New Source Review (NSR) Consent Decree. In spite of this potential, this AEP-East IRP requires no new baseload capacity resources in the forecast period. Rather, the proposed EPU initiative at the Cook Station during the 2014-2018 time period and peaking resources required in 2017 and 2018, in addition to wind purchases and DSM are proposed to be added to maintain anticipated minimum PJM nominal (capacity) reserve margin requirements (approximately 15.5% increasing to 16.2%) as well as system reliability/restoration needs. Additional natural gas-fired peaking and intermediate capacity would be added after 2020 to meet future load obligations.

5.3 Ancillary Services

In addition to energy products, PJM provides markets for ancillary services that can be sold by AEP-East generating units in support of the generating and transmission system operated by PJM. Such real-time ancillary markets include (1) regulation, (2) synchronized or spinning reserve, and (3) black start.

Regulation is a form of load-following that corrects for short-term changes in electricity use that might affect the stability of the power system. Synchronized reserve supplies electricity if the grid has an unexpected need for more power on short notice. Black start service supplies electricity for system restoration in the unlikely event that the entire grid would lose power.

Prior to the formation of RTOs, these services were provided in a routine manner by the generating units; there were no markets for them, but the costs were recovered through regulated rates. Potential revenue streams from these services have not been taken directly into account in the IRP in terms of unique resource offerings, but AEP is beginning to account for them in some special applications, such as the evaluation of battery (storage) technology.

5.4 RTO Requirements and Future Considerations

In developing the plans for the AEP-East zone, it was assumed that several factors would remain constant. As indicated, AEP is committed to the FRR alternative to the RPM of PJM through the 2012/2013 delivery year, and it was assumed that this commitment would continue indefinitely. Although PJM could contemplate further changes in the IRM, it was also assumed that the PJM IRM would be 15.3%, as currently set for the 2013/14 planning year and remain unchanged for the remainder of the Planning Period. Finally, it was assumed that the underlying PJM EFORd for 2013/14 (6.30%) would remain unchanged for the remainder of the Planning Period.

On the other hand, it was assumed that the AEP unit EFORd would change through time. Existing unit EFORds were projected to change as unit improvements are made or as units near retirement. Also, the addition of new units and removal of old units from the system changes the weighted average EFORd. With the exception delivery year 2010/11, which was heavily impacted by the Cook outage, AEP’s EFORd is projected to improve from 8.41% in 2009/10 to 5.02% in 2020/11.



40

This assumption tends to reduce the amount of new installed capacity needed to meet PJM requirements.

The inclusion of First Energy (FE) and Duke/Cinergy in the PJM footprint will impact the PJM IRM determination for the forecast period. The PJM study entitled 2009 PJM Reserve Requirement Study for the 11-Year Planning Horizon June 1st 2009 - May 31st 2020 dated November 4, 2009 by the PJM Staff included sensitivity study to evaluate the effect of the ATSI move to the PJM footprint. The study did not, however, evaluate the effect of Duke/Cinergy move to PJM Interconnection as this was announced after the completion of the study. The 2010 study should consider the Duke/Cinergy move from Midwest ISO to PJM Interconnection.

Second, the future valuation of AEP exposed generating assets take into consideration the costs profiles relative to the wholesale market position. The integrated dispatch of FE and Allegheny and the move of Duke/Cinergy generating assets to PJM will impact the PJM wholesale power markets and thus, in turn, the valuation of the AEP exposed generating assets

Beyond the FE and Duke/Cinergy matters, a FERC regulatory matter of note the November, 2009 FERC Declaratory Order issued in response to a petition from SunEdison related to solar energy installations and "retail" energy sales behind the utility meter. This order illustrates the direction of federal policy and how new entrants and new technologies are evolving with respect to retail electricity sales and the intersection of State jurisdictional net metering and FERC jurisdictional wholesale regulations.

5.5 Capacity Positions—Historical Perspective

To provide a perspective, an historical relative capacity position for the AEP-PJM zone is presented in Exhibit 5-2. AEP’s East zone (as part of ECAR) experienced ample capacity reserves throughout the decade of the 1980s and most of the 1990s. In the early 2000s the trending clearly suggested that anticipated load growth would soon result in zonal capacity deficiencies, on a planning basis. The economic decline that occurred over the past two years has again allowed AEP’s East zone to maintain an adequate capacity position however, given the volatility that has been experienced over the past decade, it would be prudent to maintain a flexible plan that can react to quick changes.



41

Exhibit 5-2: AEP Eastern Zone, Historical Capacity Position


AE

P S

YS

TE

M -

EA

ST

ER

N Z

ON

EC

AP

AC

ITY

SU

RP

LUS

Nec

essa

ry to

Mai

ntai

n P

JM-M

anda

ted

Res

erve

Mar

gin

1984

- 2

009

0

500

1,00

0

1,50

0

2,00

0

2,50

0

3,00

0

3,50

0

4,00

0

4,50

0

5,00

0

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Capacity Surplus (MW)

05,00

0

10,0

00

15,0

00

20,0

00

25,0

00

30,0

00

Summer Peak (MW)

Sur

plus

/(D

efic

ienc

y)

Sum

mer

Pea

k D

eman

ds (

Nor

mal

ized

)

Roc

kpor

t 1

Roc

kpor

t 2Zim

mer

Ces

satio

n of

R

ockp

ort/

VE

PC

o S

ale

AE

P E

ast s

hifts

fully

to

Sum

mer

pea

king

Axi

s Y

2:Y

1 R

atio

is 6

to 1



42



43

6.0 Resource Options

6.1 Resource Considerations

An objective of a resource planning effort is to recommend an optimum system expansion plan, not only from a least-cost perspective, but also from the perspectives of planning flexibility, creation of an optimum asset mix, adaptability to risk, conformance with applicable NERC Standards and, ultimately, from the perspective of affordability. In addition, given the unique impact of generation on the environment, the planning effort must ultimately be in concert with anticipated long-term requirements as established by the environmental compliance planning process.

6.1.1 Market Purchases

AEP’s planning position for its East Zone is to take advantage of market opportunities when they are available and economic, either in the form of limited-term bilateral capacity purchases from non-affiliated sources or by way of available, discounted, merchant generation asset purchases. Such market opportunities could be utilized to hedge capacity planning exposures should they emerge and create (energy) option value to the company.

As with the need to maintain resource planning and implementation flexibility for various supply or demand exposures as identified above, the Plan should likewise seek to continually consider such market “buy” prospects, since:

this IRP assumes the need to ultimately build generating capability to meet the requirements of its customers for which it has assumed an obligation to serve (including Ohio);

the regional market price of capacity ultimately will, as represented above, begin to approach the fixed cost of new-build generation; and

the purchase of merchant generation assets relative to new-build generation represents a different risk profile with respect to siting, costs and schedule.

Another critical element ultimately impacting the availability of (bilateral) market capacity purchases is the PJM RPM construct. As discussed, AEP has opted out of the RPM capacity auction. With that, however, comes the fact that the capacity supply available to AEP would be limited to other “FRR” entities within PJM (which are limited), or to capacity resources residing outside of the PJM RTO. However, AEP has an option to participate in RPM so long as AEP remains an RPM participant for no less than 5 years.

6.1.2 Generation Acquisition Opportunities

Other market purchase opportunities are constantly being explored in continued recognition of the need for additional capacity. AEP investigates the viability of placing indicative offers on additional utility or IPP-owned natural gas peaking and combined cycle facilities as such opportunities arise. Analyses are performed in the Strategist resource optimization model based on the most recent IRP studies, to estimate a break-even purchase price that could be paid for the early



44

acquisition of such an asset, in lieu of an ultimate green field installation. However, as shown in Exhibit 6-1, the cost of these available assets are now beginning to approach that of a greenfield project.

Exhibit 6-1: Recent Merchant Generation Purchases

0

100

200

300

400

500

600

700

800

900

1000

2004 2005 2006 2007 2008 2009 2010

$/kW

(P

urc

has

ed/C

om

ple

ted

)

Waterford CC(AEP)

Ceredo CT (AEP) Darby CT (AEP)

Lawrenceburg CC (AEP)

Greenville CT (Buckeye)

Dresden CC (AEP)

Zeeland CC/CT (Consumers)Fremont CC (First Energy)

Current greenfield CT-CC cost range

Rolling Hills (Tenaska)

Rocky Mountain CC/Blue Spruce CT (Xcel)


6.2 Traditional Capacity-Build Options

6.2.1 Generation Technology Assessment and Overview

AEP’s New Generation organization is responsible for the tracking and monitoring of estimated cost and performance parameters for a wide array of generation technologies. Utilizing access to industry collaboratives such as EPRI and Edison Electric Institute, AEP’s association with architect and engineering firms and original equipment manufacturers as well as its own experience and market intelligence, this group continually monitors supply-side trends. Appendix C offers a summary of the most recent technology performance parameter data developed.

6.2.2 Baseload Alternatives

Coal-based baseload technologies include pulverized coal (PC) combustion designs, integrated gasification combined cycle (IGCC), and circulating fluidized bed combustion (CFB) facilities. Nuclear is a viable option, and the application process for the construction of nuclear power plants has been initiated by several utilities. It is the current view of AEP that, while great difficulty and risk still exist in the siting and construction of nuclear power plants, nuclear power should be among the baseload options for the future. Nuclear power was modeled in some scenarios and sensitivities,



45

but ultimately was not included in the final resource plan being recommended due to the uncertainties surrounding costs, schedules, and regulatory recovery.

6.2.2.1 Pulverized Coal

PC plants are the workhorse of the U.S. electric power generation industry. In a PC plant, the coal is ground into fine particles that are blown into a furnace where combustion takes place. The heat from the combustion of coal is used to generate steam to supply a steam turbine that drives a generator to produce electricity. Major by-products of combustion include SO2, NOX, CO2, and ash, as well as various forms of elements in the coal ash including mercury (Hg). The ash byproduct is often used in concrete, paint, and plastic applications.

Steam cycle thermodynamics for the pulverized coal-fired units–which determines the efficiency of generating electricity– falls into one of two categories, subcritical or supercritical. Subcritical operating conditions are generally accepted to be at up to 2,400 psig/1,000°F superheated steam, with a single or double reheat systems to 1,000°F, while supercritical steam cycles typically operate at up to 3,600 psig, with 1,000-1,050°F main steam and reheat steam temperatures. AEP has recognized the benefits of the supercritical design for many years. All eighteen of the units in the AEP East system built since 1964 have utilized the supercritical design.

There have been advances in the supercritical design over the years, and units are now being designed to operate at or above 3,600 psig and >1,100°F steam temperatures, known as an ultra supercritical (USC) design. AEP’s Turk plant which is currently under construction in Arkansas is a new USC design.

The initial capital costs of subcritical units are lower than those of a comparable supercritical unit by about 4 to 6%, but the overall efficiency of the supercritical design is higher than the subcritical design by approximately 3%. Due to cycle design improvements, the new variable pressure ultra supercritical units are projected to have an initial capital cost of about 4% greater than a comparable supercritical unit. While the overall efficiency remains approximately 3% better than the comparable supercritical unit, the efficiency improvement is present throughout the entire load range, not just at full load conditions.

This cost-performance tradeoff favors USC designs as fuel and carbon prices increase.

6.2.2.2 Integrated Gasification Combined Cycle

Given the long time-horizons of most resource planning exercises, IRP processes must be able to consider new technologies such as IGCC. The assessment of such technologies is based on cost and performance estimates from commonly cited public sources, consortia where AEP is actively engaged, and vendor relationships, as well as AEP’s own experience and expertise.

IGCC is of particular interest to AEP in light of the abundance, accessibility, and affordability of high rank coals for the company–particularly in its eastern zone. IGCC technology with carbon capture has the potential to achieve the environmental benefits closer to those of a natural gas-fired plant, and thermal performance closer to that of a combined cycle, yet with the low fuel cost



46

associated with coal. As discussed in this IRP report, the coal gasification process appears well-positioned for integration of ultimate carbon capture and storage technologies, which will be a critical measure in any future mitigation of greenhouse gas emissions associated with the generation of electricity. The IGCC process employs a gasifier in which coal is partially combusted with oxygen and steam to form what is commonly called “syngas”–a combination of carbon monoxide, methane, and hydrogen. The syngas produced by the gasifier then is cleaned to remove the particulate and sulfur compounds. Sulfur is converted to hydrogen sulfide and ash is converted into glassy slag. Mercury is removed in a bed of activated carbon. The syngas then is fired in a gas turbine. The hot exhaust from the gas turbine passes to a heat recovery steam generator (HRSG), where it produces steam that drives a steam turbine as would a natural gas-fired combined cycle unit.

IGCC enjoys thermal efficiencies comparable to USC-PC. Its ability to utilize a wide variety of coals and other fuels positions it extremely well to address the challenges of maintaining an adequate baseload capability with efficient, low-emitting, low-variable cost generating technology. Further, IGCC is in a unique position to be pre-positioned for carbon capture as, unlike PC technologies, it has the ability to perform such capture on a “pre-combustion” basis. It is believed that this will ultimately lead to improved net thermal efficiency than would be required by PC technology utilizing post-combustion carbon capture technology.

6.2.2.3 Circulating Fluidized Bed Combustion

A CFB plant is similar to a PC plant except that the coal is crushed rather than pulverized, and the coal is combusted in a reaction chamber rather than the furnace of a PC boiler. A CFB boiler is capable of burning bituminous and sub-bituminous coal plus a wide range of fuels that cannot be accommodated by PC designs. These fuels include, coal waste, lignite, petroleum coke, a variety of waste fuels, and biomass. Units are sometimes designed to fire using several fuels, which emphasizes this technology’s major advantage fuel flexibility. Coal is combusted in a hot bed of sorbent particles that are suspended in motion (fluidized) by combustion air blown in from below through a series of nozzles. CFB boilers operate at lower temperatures than pulverized coal-fired boilers. The energy conversion efficiency of CFB plants tends to be slightly lower than that of pulverized coal-fired counterparts of the same size and steam conditions because of higher excess air and auxiliary power requirements.

CFB boilers capitalize on the unique characteristics of fluidization to control the combustion process, minimize NOX formation, and capture SO2 in situ. Specifically, SO2 is captured during the combustion process by limestone being fed into the bed of hot particles that are fluidized by the combustion air blown in from below. The limestone is converted into free lime, which reacts with the SO2. Currently, the largest CFB unit in operation is 320 MW, but designs for units up to 600 MW have been developed by three of the major CFB suppliers. A 500 MW unit is in initial stage of operations in Poland. AEP has no commercial operating experience with generation utilizing circulating fluidized bed boilers but is familiar with the technology through prior research, including the Tidd pressurized fluidized bed demonstration project. Commercial CFB units utilize a subcritical steam cycle, resulting in a lower thermal efficiency.



47

6.2.2.4 Carbon Capture

CO2 capture is the separation of CO2 from a flue gas stream or from the atmosphere and the recovery of a concentrated stream of CO2 that is suitable for storage or conversion. Efforts are focused on systems for capturing CO2 from coal-fired power plants, although the technologies developed will need to also be applicable to natural-gas-fired power plants, industrial CO2 sources, and other applications. In PC plants, which are 99% of all coal-fired power plants in the United States, CO2 is exhausted in the flue gas at atmospheric pressure at a concentration of 10-15% volume. This is a challenging application for CO2 capture because:

The low pressure and low CO2 concentration dictate a high volume of gas to be treated.

Trace impurities in the flue gas tend to reduce the effectiveness of the CO2 absorption processes.

CO2 capture processes require large amounts of steam and electricity to separate the CO2 from the flue gas stream thereby increasing unit heat rates, increasing auxiliary power requirements and reducing the electrical energy available for delivery to ultimate customers.

Compressing captured CO2 from atmospheric pressure to pipeline pressure (1,200 to 2,000 pounds per square inch) adds to the large parasitic load.

Aqueous amines are the current state-of-the-art technology for CO2 capture for PC power plants. The 2020 Department of Energy aspirational goal for advanced CO2 capture systems is that CO2 capture and compression added to a newly constructed power plant increases the cost of electricity no more than 35%, versus the current 65%, relative to a no-capture case.

However, with IGCC technology, CO2 can be captured from a synthesis gas (coming out of the coal gasification reactor) before it is mixed with air in a combustion turbine. The pre-combusted CO2 is relatively concentrated (50% of volume) and at higher pressure. These conditions offer the opportunity for lower-cost CO2 capture. The 2012 Department of Energy aspirational goal for advanced CO2 capture and storage systems applied to an IGCC is no more than a 10% increase in the cost of electricity from the current 30%. It is a more stringent goal even though the conditions for CO2 capture are more favorable in an IGCC plant.

6.2.2.4.1 Carbon Capture Technology and Alternatives

Reducing CO2 emissions from a fossil-fuel technology can be accomplished in three ways: increased generating efficiency thereby lowering the emission rate or CO2 produced per unit of electric energy produced, removing the CO2 from the flue gas, or reducing the carbon content of the fuel. While effective, increasing the generating efficiency of a coal-based plant has its practical limitations from a design and performance perspective. Removing the CO2 from the flue gas of a PC plant is a very expensive process. Currently, the only demonstrated technology used to “scrub” the CO2 from the flue gas is by using an amine-based absorption process.

As previously mentioned in this report, AEP is pursuing an alternative approach. AEP is currently conducting a validation of Alstom’s chilled ammonia PC carbon capture technology on a 20



48

MW flue gas slipstream at its 1,300 MW Mountaineer Plant in West Virginia. It is anticipated that this technology, when fully developed, will achieve 90% CO2 capture with a 15% parasitic loss and netting a lower cost than other retrofit technologies. Based on the results of the Mountaineer slip-stream test, a subsequent 235 MW commercial installation of this chilled ammonia technology is in the early stage of Phase I development for Mountaineer.

This 235 MW cost/performance profile will be modeled in subsequent IRPs.

6.2.2.5 Carbon Storage

Storage is the placement of CO2 into a repository in such a way that it will remain stored for hundreds of thousands of years.

Geologic formations considered for CO2 storage are layers of porous rock deep underground that are “capped” by a layer of nonporous rock above them. The storage process consists of drilling a well into the porous rock and then injecting pressurized (“spongy” liquid) CO2 into it. The CO2 is buoyant and flows upward until it encounters the layer of nonporous rock and becomes trapped. There are other mechanisms for CO2 trapping as well. CO2 molecules dissolve in brine and react with minerals to form solid carbonates, or are absorbed by porous rock. The degree to which a specific underground formation is suitable for CO2 storage can be difficult to discern. Research is aimed at developing the ability to characterize a formation before CO2 injection to be able to predict its CO2 storage capacity. Another area of research is the development of CO2 injection techniques that achieve broad dispersion of CO2 throughout the formation, overcome low diffusion rates, and avoid fracturing the cap rock. These two areas, site characterization and injection techniques, are interrelated because improved formation characterization will help determine the best injection procedure.

6.2.2.6 Nuclear

Although new reactor designs and ongoing improvements in safety systems make nuclear power an increasingly viable option as a new-build alternative due to it being an emission-free power source, concerns about public acceptance/permitting, spent nuclear fuel storage, lead-time, capital costs and completion risk continue to temper its consideration. For these stated reasons, among others, AEP does not view new new nuclear capability as a viable candidate to meet the capacity resource needs of AEP-East within this near-term period (2010-2020). However, portfolios that include nuclear capacity beyond the near-term period and into the expected second wave of new builds are comparable with the hybrid portfolio that was ultimately selected. Both the economic and political viability of nuclear power and energy will continue to be explored given:

1) the AEP-East zone’s ultimate need for baseload capacity;

2) the cost and performance uncertainty surrounding the advancement and commercialization of IGCC technology;

3) the cost and performance uncertainty of carbon capture and storage technology; and



49

4) the continued push to address AEP’s carbon footprint and the mitigating impact additional nuclear power clearly would have in that regard.

Growth in U.S. nuclear generation since 1977 has been primarily achieved through “uprating” – the practice of increasing capacity at an existing nuclear power plant. As of October 2009, the NRC had approved 129 uprates totaling 5,726 MWe of capacity. That amount is equivalent to adding another five-to-six conventional-sized nuclear reactors to the electricity supply portfolio. Extended power uprates (EPU) can provide up to 20% of additional capacity. The EPU and related projects for the Cook Plant (as described in Section 3.2.1 of this report) – are therefore consistent with the recent trends in the nuclear industry.

6.2.3 Intermediate Alternatives

Intermediate generating sources are typically expected to serve a load-following and cycling duty and shield baseload units from that obligation. Historically, many generators, such as AEP’s eastern fleet, have relied on older, less-efficient, subcritical coal-fired units to serve such load-following roles. Over the last several years, these units’ staffs have made strides to improve ramp rates, regulation capability, and reduce downturn (minimum load capabilities). As the fleet continues to age and sub-critical units are retired, other generation dispatch alternatives and new generation will need to be considered to cost effectively meet this duty cycle’s operating characteristics.

6.2.3.1 Natural Gas Combined Cycle (NGCC)

An NGCC plant combines a steam cycle and a combustion gas turbine cycle to produce power. Waste heat (~1,100°F) from one or more combustion turbines passes through a heat recovery steam generator (HRSG) producing steam. The steam drives a steam turbine generator which produces about one-third of the NGCC plant power, depending upon the gas-to-steam turbine design “platform,” while the combustion turbines produce the other two-thirds.

The main features of the NGCC plant are high reliability, reasonable capital costs, operating efficiency (at 45-55% LHV), low emission levels, small footprint and shorter construction periods than coal-based plants. In the past 8 to 10 years NGCC plants were often selected to meet new intermediate and certain baseload needs. Although cycling duty is typically not a concern, an issue faced by NGCC when load-following is the erosion of efficiency due to an inability to maintain optimum air-to-fuel pressure and turbine exhaust and steam temperatures. Methods to address these include:

Installation of advanced automated controls.

Supplemental firing while at full load with a reduction in firing when load decreases. When supplemental firing reaches zero, fuel to the gas turbine is cutback. This approach would reduce efficiency at full load, but would likewise greatly reduce efficiency degradation in lower-load ranges.

Use of multiple gas turbines coupled with a waste heat boiler that will give the widest load range with minimum efficiency penalty.



50

6.2.4 Peaking Alternatives

Peaking generating sources are required to provide needed capacity during extreme high-use peaking periods and/or periods in which significant shifts in the load (or supply) curve dictate the need for “quick-response” capability. The peaks occur for only a few hours each year and the installed reserve requirement is predicated on a one day in ten year loss of load expectation, so the capacity dedicated to serving this reliability function can be expected to provide very little energy over an annual load cycle. As a result, fuel efficiency and other variable costs are of less concern. This capacity should be obtained at the lowest practical installed cost, despite the fact that such capacity often has very high energy costs. For this reason, acquisition of existing gas generation assets at below market prices is the preferred choice for meeting peaking requirements. This peaking requirement is manifested in the system load duration curve, an example of which is shown in Exhibit 6-2. This curve shows the hourly demand for each hour in a typical year. Note that there is a notable drop off in demand after the highest 3% of the hourly loads. This drop off supports the position that the lowest installed cost investment, or lowest life cycle cost investment when considering the minimal capacity factors these peaking facilities will experience, are selected by optimization modeling.

In addition, in certain situations, peaking capacity such as combustion turbines can provide backup and some have the ability to provide emergency (Black Start) capability to the grid.

Exhibit 6-2: AEP East Typical Load Duration Curve


AEP East Load Shape Typical Planning Period Year

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

0%

2%

5%

7%

9%

11%

14%

16%

18%

20%

23%

25%

27%

30%

32%

34%

36%

39%

41%

43%

45%

48%

50%

52%

55%

57%

59%

61%

64%

66%

68%

70%

73%

75%

77%

80%

82%

84%

86%

89%

91%

93%

95%

98%

100

% of Hours (Cumulative)

MW

Reserve margin requirement

tier 1

The MW values on the left represent 2 tiers of possible peaking duty employment:

1. The Reserve Requirement: this represents 15.5% of the forecasted peak. Since this is capacity that is, by definition, not planned for use, it should arguably be satisfied with the

lowest (fixed) cost resource (peaking - to include DR)2. 3% of the hours. This is the forecasted peak, using an

arbitrary designation of 3%. It also should be satisfied with the lowest (fixed) cost resource (peaking - to include DR)

This suggests that the ultimate plan would support having a significant portion if its capacity (20- 25%) provided by peaking duty cycle resources, which

would include Demand Side Initiatives (DR/EE)

tier 2



51

6.2.4.1 Simple Cycle Combustion Turbines (NGCT)

In “industrial” or “frame-type” combustion turbine systems, air compressed by an axial compressor (front section) is mixed with fuel and burned in a combustion chamber (middle section). The resulting hot gas then expands and cools while passing through a turbine (rear section). The rotating rear turbine not only runs the axial compressor in the front section but also provides rotating shaft power to drive an electric generator. The exhaust from a combustion turbine can range in temperature between 800 and 1,150 degrees Fahrenheit and contains substantial thermal energy. A simple cycle combustion turbine system is one in which the exhaust from the gas turbine is vented to the atmosphere and its energy lost, i.e., not recovered as in a combined cycle design. While not as efficient (at 30-35% LHV), they are, however, inexpensive to purchase, compact, and simple to operate. Further, simple cycle frame CTs can be started up and placed in service far more rapidly (30 minutes) than a combined cycle unit requiring four or more hours from start to full load resulting from the CC unit thermal steam cycle.

6.2.4.2 Aeroderivatives (AD)

Aeroderivatives are aircraft jet engines used in ground installations for power generation. They are smaller in size, lighter weight, and can start and stop quicker than their larger industrial or "frame" counterparts. For example, the GE 7EA frame machine requires 20 minutes to ramp up to full load while the smaller LM6000 aeroderivative only needs 10 minutes from start to full load. However, the cost per kW of an aeroderivative is on the order of 20% higher than a frame machine.

The AD performance operating characteristics of rapid startup and shutdown, make the aeroderivatives well suited to peaking generation needs. The aeroderivatives can operate at full load for a small percentage of the time allowing for multiple daily startups to meet peak demands, compared to frame machines which are more commonly expected to start up once per day and operate at continuous full load for 10 to 16 hours per day. The cycling capabilities provide aeroderivatives the ability to backup variable renewables such as solar and wind. This operating characteristic is expected to become more valuable over time as: a) the penetration of variable renewables increase, b) baseload generation processes become more complex limiting their ability to load follow and; c) intermediate coal-fueled generating units are retired from commercial service.

Aeroderivatives weigh less than their industrial counterparts allowing for skid or modular installations. Efficiency is also a consideration in choosing an aeroderivative over an industrial turbine. Aeroderivatives in the less than 100 MW range are more efficient and have lower heat rates in simple cycle operation than industrial units of equivalent size. Exhaust gas temperatures are lower in the aeroderivative units.

Some of the better known aeroderivative vendors and their models include GE's LM series, Pratt & Whitney's FT8 packages, and the Rolls Royce Trent and Avon series of machines.5

5 Turbomachinery International, Jan/Feb. 2009; Gas Turbine World; EPRI TAG



52

6.2.5 Energy Storage

Energy storage refers to technologies that allow for storage of energy during off-peak periods of demand and discharge of energy during periods of peak demand. This has the effect of flattening the load curve by reducing the peaks and “filling the valleys.” In this sense, it is considered a peaking asset. Energy storage can also be applied at other times to temporarily mitigate transmission congestion if it is economically to do so in conjunction with generating resources that are curtailed by inadequate transmission infrastructure. Energy storage consists of batteries (Sodium Sulfur “NaS,” Lithium Ion, and others), super capacitors, flywheels, compressed air energy storage (CAES) or pumped hydro storage. Pumped storage hydro uses two water reservoirs, separated vertically. During off peak hours water is pumped from the lower reservoir to the upper reservoir. When required, the water flow is reversed to generate electricity.

The investment requirements for pumped hydro storage are significant. Further, site-selection and attainment of FERC licensing represent huge challenges. NaS Batteries are the leading technology under consideration for prospective storage-related utility planning with several variations of compressed air energy storage in research and development.

6.2.5.1 Sodium Sulfur Batteries (NaS):

Storage technologies are receiving greater consideration due partly to the improved battery-storage technologies; efficiencies now are approaching 90%. That, coupled with the ability to offer market time-of-day pricing arbitrage by charging during low-cost off-peak periods and discharging at higher-cost daytime periods, works to its advantage. Battery installations can be located near load points, thus avoiding transmission and distribution line losses associated with traditional generation. The downside currently is the significant manufactured cost per kW, transportation limitations due to their weight, and total installed costs in the range of $2,000 per kW.

In light of battery-storage’s potential for: 1) market arbitrage, 2) line loss reduction, 3) deferral of selected distribution infrastructure through selective siting of storage capacity, coupled with the prospect for reduced capital costs due to improvements in battery technology, its consideration as a potential capacity resource is warranted.

6.2.5.2 Community Energy Storage (CES)

Community energy storage (CES) is being tested as a distributed storage option. The use of distributed storage technology, which will involve the placement of small energy storage batteries throughout residential areas, will look similar to the small transformer boxes currently seen throughout neighborhoods. Each box should be able to power four to six houses. AEP is testing this potential distribution game-changing technology, which should also provide voltage sag mitigation as well as emergency transformer load relief.



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6.3 Renewable Alternatives

Renewable generation alternatives use energy sources that are either naturally occurring (wind, solar, hydro or geothermal), or are sourced from a by-product or waste-product of another process (biomass or landfill gas). Numerous renewable energy sources such as solar, geothermal, new hydro, and tidal are either under development or exist. However not all are economic options for AEP within the service territory based on their current state of development, or for financial, meteorological, or geographical reasons. Within the AEP service territory, without significant leaps in technology, biomass co-firing in coal power plants and wind power plants are the primary options for economically (or realistically) generating electricity on a significant scale from renewable sources.

As highlighted in the Section 2 Introduction, although effective in 29 states (9 of 13 PJM states) plus the District of Columbia, a mandatory RPS exists today in Ohio, West Virginia and Michigan, and a voluntary RPS exists in Virginia. The prospect of a Federal RPS and additional state standards is sufficiently tenable to warrant an evaluation of renewable generation in conjunction with this IRP process. Further, renewable energy sources deliver attractive CO2 benefits in a potentially carbon-constrained policy environment, should that environment be realized.

AEP’s New Technology Development group continues to evaluate a wide range of renewable technologies, with the latest updates (December 2009) included in Appendix I. Technologies were evaluated on cost, location, feasibility, applicability to AEP’s service territory, and commercial availability. After a high-level evaluation, economic screening was carried out considering each technology’s estimated costs and effectiveness, to develop a levelized $/MWh cost. Costs and benefits considered in the screening included project capital and O&M costs; avoided capacity and energy costs; alternative fuel costs; alternative emission rates and associated allowance costs; and available federal or state production tax credits, if any. The levelized cost was used to rank the various technologies and also was compared to AEP-East’s avoided cost to calculate an imputed REC value. A project is considered reasonable if the projected market value of equivalent RECs is greater than this imputed REC value for a particular technology.

The renewable technologies ultimately screened include:

biomass co-firing on existing coal-fired units

separate injection of biomass on existing coal-fired units

wind farms evaluated separately for the East and West regions with or without the federal production tax credit & investment tax credit

solar generation with or without the federal investment tax credit

incremental hydroelectric production

landfill gas with microturbine

geothermal generation

distributed generation.

Although some of the renewable technologies listed above could be economic, AEP is constrained from doing some of these projects because the energy sources are not practical in AEP



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service territory (e.g., geothermal). Similarly, biomass co-firing is constrained by a supply of suitable fuel and/or transportation options anticipated to be in proximity to the host coal units evaluated. Thus, the renewable resources available to be included in the Plan are not necessarily the least expensive options screened, but rather those that provide suitable economics and practicality to achieve emerging state or federal mandates.

6.3.1 Wind

Wind is currently the fastest growing form of electricity generation in the world. Utility wind energy is generated by wind turbines with a range 1.0 to 2.5 MW, with a 1.5 MW turbine being the most common size used in commercial applications today with over 25,000 MW of wind online as of January 2010. Typically, multiple wind turbines are grouped in rows or grids to develop a wind turbine power project which requires only a single connection to the transmission system. Location of wind turbines at the proper site is particularly critical from the perspective of both the existing wind resource and its proximity to a transmission system with available capacity.

Ultimately, as turbine production increases to match the significant increase in demand, the high capital costs of wind generation should begin to decline. Currently, the cost of electricity from wind generation is becoming competitive within the AEP-East zone due largely, however, to subsidies, such as the federal production tax credit as well as consideration given to REC values, anticipated rising fuel costs or future carbon costs.

A drawback of wind is that it represents a variable source of power in most non-coastal locales, with capacity factors ranging from 30 to 45 percent; thus its life-cycle cost ($/MWh), excluding subsidies, is typically higher than the marginal (avoided) cost of energy, in spite of wind’s zero dollar fuel cost. Another obstacle with wind power is that its most critical factors (i.e., wind speed and sustainability) are typically highest in very remote locations, and this forces the electricity to be transmitted long distances to load centers necessitating the buildout of EHV transmission to optimally integrate large additions of wind into the grid. Exhibit 6-3 shows the wind resource locations in the U.S. and their relative potential.



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Exhibit 6-3: United States Wind Power Locations

Source: U.S. Department of Energy

6.3.2 Solar

Solar power takes a couple of viable forms to produce electricity: concentrating and photovoltaics. Concentrating solar – which heats a working fluid to temperatures sufficient to power a turbine - produces electricity on a large scale (100 MW) and is similar to traditional centralized supply assets in that way. Photovoltaics produce electricity on a smaller scale (2 kW to 20 MW per installation) and are distributed throughout the grid. In the AEP-East zone, solar has applications as both large scale and distributed generation. The appeal of solar is broad and recent legislation in Ohio has made its pursuit mandatory subject to rate impacts, beginning in 2009. Solar photovoltaics are represented in this IRP as though this full solar requirement is to be met in Ohio. However, the amounts of solar prescribed in the law, while substantial, will not have a significant effect on the timing or amount of other supply assets within a ten-year planning period. Exhibit 6-4 shows the potential solar resource locations in the U.S.



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Exhibit 6-4: United States Solar Power Locations

Source: NREL

6.3.3 Biomass

Biomass is a term that typically includes organic waste products (sawdust or other wood waste), organic crops (corn, switchgrass, poplar trees, willow trees, etc.), or biogas produced from organic materials, as well as select other materials.

It is generally accepted that sustainably produced biomass represents a carbon neutral fuel. Carbon from the atmosphere is converted into biological matter by photosynthesis. Upon combustion, the carbon returns to the atmosphere as carbon dioxide (CO2) where it can be recaptured by new biomass growth replacing the biomass used as fuel. Therefore a reasonably stable level of atmospheric carbon results from its use as a fuel.

In the United States today, a large percentage of biomass power generation is based on wood-derived fuels, such as waste products from the pulp and paper industry and lumber mills. Biomass from agricultural wastes also plays a dominant role in providing fuels. These agricultural wastes include rice and nut hulls, fruit pits, and manure.



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A relatively low-cost option to produce electricity by burning biomass is by co-firing it with coal in an existing boiler using existing coal feeding mechanisms. In a typical biomass co-firing application, 1.5% to 6% of the generating unit’s heat input is provided by biomass, depending on the boiler’s method of firing coal. A more capital-intensive option is separate injection, which involves separate handling facilities and separate injection ports for the biomass. Separate injection can achieve a 10% heat input from biomass.

Co-firing generally provides a lower-cost method of energy generation from biomass than building a dedicated biomass-to-energy power plant. In addition, a coal-fired power plant typically uses a more efficient steam cycle and consumes relatively less auxiliary power than a dedicated biomass plant, and thus generates more power from the same quantity of biomass.

Some possible drawbacks associated with biomass co-firing or separate injection include reduced plant efficiencies due to lower energy content fuels, loss of fly ash sales, and fouling of SCR catalysts used to remove NOX from the exhaust gas. Although these relatively minor obstacles can be mitigated through various means, the major obstacles to the utilization of biomass as a feedstock include volatile costs of transportation and substitute uses for the fuel. Biomass has many competing demands, such as the pulp and paper markets, agriculture industries, and the ethanol market, which can dramatically escalate the market price for the material along with the transportation of such a low energy-density fuel. Another issue associated with biomass is the significant quantities of dedicated land necessary to generate sufficient quantities of biomass as identified in Exhibit 6-5.

Exhibit 6-5: Land Area Required to Support Biomass Facility

Switchgrass Wood Chips / Sawdust (per Purdue University Study) (per AEP-Forestry)

o 6 -to- 8 tons /yr. per acre yield o 70 -to-100 tons /yr. per acre yield*o @ 6700 Btu/lb (non-dried, as harvested) * "clear cutting" on a 40-year cycle

o @ 4800 Btu/lb (green, non-dried)

A 200-MW Dedicated Biomass Facility A 200-MW Dedicated Biomass Facility (70% C.F.) would require… (70% C.F.) would require…

110k -to- 150k harvested acres 510k -to- 730k timbered acres (172 - 234 sq. mi,) (795 - 1,140 sq. mi,)

10-GW (~60 Twh/yr.) of switchgrass-fired biomass capacity 10-GW of (clear-cut) wood chip-fired capacity would would require approx. 45 MM t/yr. of switchgrass which require approx. 64 MM t/yr. of wood product which would would require dedicated agri-land mass = 6.5 MM acres require dedicated forested-land mass = 31 MM acres

… or 100% of the cropland and pasture/grassland … or 100% of the forested acreage identified by the USDA identified by the USDA in the state of Georgia in North Carolina and South Carolina combined


Biomass utilization provides many valuable benefits and holds some promise for the AEP generating fleet, but the high fuel/transportation costs and the limited deployment potential on a heat-input basis inhibits the near-term viability of the technology on a large scale. Exhibit 6-6 shows potential biomass resources.

Biomass utilization is not a substitute for additional generation. Because it simply substitutes “carbon-neutral” fuel for fossil fuels, it does not eliminate the need for building generation as demand grows and assets are retired. However, if and when GHGs become regulated, biomass co-firing could become an economically viable way to reduce the CO2 output of certain coal-fired plants.



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Exhibit 6-6: Biomass Resources in the United States

Source: NREL

6.3.4 Renewable Energy Certificates (RECs)

An additional option for complying with renewable standards involves the purchase of renewable energy certificates, or “RECs”. RECs are generated contaminant with carbon-neutral energy, but are sold separately providing the energy produced is sold into the relevant grid. This arrangement allows for efficient transfer of costs from over-producers to under-producers of required carbon-neutral energy. In nascent markets, where over-production does not exist, RECs will be scarce or non-existent, driving values high. High REC values, in turn, will foster additional capital investment, until REC values reach equilibrium.

In AEP-East zone states with renewable requirements (Ohio and Michigan), REC markets exist or are developing for renewable (in-state and deliverable) and solar (in-state and deliverable) but are not yet reliable sources for compliance.



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6.3.5 Renewable Alternatives—Economic Screening Results

AEP has established an internal renewable target of 10% of System energy (total East and West zones) from renewable resources by 2020 (see Appendix E). Based on current AEP renewable resources, and considering an additional 1,000 MW of renewable resources committed to by the year-end 2014, together with the prospective renewable projects listed in Exhibit 6-7, included in the 2010 IRP (AEP-East and SPP), this internal commitment is projected to be satisfied. Note that the 2014 target represents an approximate 3-year shift in prior (2009 IRP) planned commitments of 2,000 MW of System-wide renewable resources by the end of 2014; however, as recent unfavorable regulatory decisions in both Virginia and Kentucky surrounding cost recovery of planned wind purchase transactions has resulted in this “extension” of that prior goal.

Exhibit 6-7: Renewable Sources Included in AEP-East and AEP-SPP 2010

Wind (SW Mesa) X 31 Existing 0.1% Existing (RECs only)Wind (Weatherford) X 147 Existing 0.5% ExistingWind (Blue Canyon II) X 151 Existing 0.9% Existing (RECs only until 2013)Wind (Sleeping Bear) X 95 Existing 1.2% ExistingWind (Camp Grove) X 75 Existing 1.4% ExistingWind (Fowler Ridge I & III) X 200 2010 1.8% Executed PPAWind (Grand Ridge II & III) X 101 2010 2.0% Executed PPAWind (Fowler Ridge II) X 150 2010 2.4% Executed PPA (Add'l take)Wind (Majestic) X 80 2010 2.6% Executed PPA (RECs only until 2012)Wind (Blue Canyon V) X 99 2010 2.9% Executed PPA (RECs only until 2013)(Add'l take)Wind (Beech Ridge) X 101 2011 3.1% Executed PPA(PSC-Apprvd)Wind (Elk City) X 99 2011 3.3% Executed PPA (RECs only until 2013)(Add'l take)Solar (Wyandot) X 10 2011 3.4% Executed PPASolar (Ohio) X 10 2011 3.4% w/ ITCBiomass (Ohio units) X 44 2011 3.5% Ohio Units 10% Co-FireWind (East) X 100 2012 3.6% w/ PTCWind (Minco) X 100 2012 3.9% Minco (PSO)Solar (Ohio) X 10 2012 3.9% w/ ITCWind (East) X 100 2013 4.1% w/ PTCSolar (Ohio) X 10 2013 4.1% w/ ITCBiomass (East) X 50 2014 4.4% RECs PPA or Unit Co-Fire (No New Capacity)Wind (East) X 300 2014 5.0% No PTCSolar (Ohio) X 26 2014 5.0% w/ ITCWind (East) X 400 2015 5.9% No PTCWind (West) X 200 2015 6.4% No PTCSolar (Ohio) X 26 2015 6.4% w/ ITCSolar (Distributed) X 25 2015 6.5% (E&W) No ITCBiomass (Ohio units) X (44) 2016 6.3% Retirement of Ohio Units 10% Co-FireWind (West) X 200 2016 6.9% No PTCWind (East) X 250 2016 7.4% No PTCSolar (Ohio) X 26 2016 7.4% No ITCWind (West) X 200 2017 7.9% No PTCWind (East) X 150 2017 8.2% No PTCSolar (Ohio) X 26 2017 8.3% No ITCSolar (Ohio) X 26 2018 8.3% No ITCWind (East) X 50 2018 8.4% No PTCBiomass (East) X 100 2018 8.9% RECs PPA or Unit Co-Fire (No New Capacity)Wind (East) X 100 2019 9.1% No PTCSolar (Ohio) X 26 2019 9.1% No ITCWind (West) X 300 2020 9.9% No PTCWind (East) X 150 2020 10.2% No PTCSolar (Ohio) X 26 2020 10.2% No ITC

AEP-SystemExisting and Projected Renewables for 2010 IRP

Sol

ar

Win

dB

iom

ass

Renewableas % ofSales

FirstFull

EnergyYear

Size(MW)

Unit, Plant, or Contract Notes

Unit Type




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6.4 Demand-Side Alternatives

6.4.1 Background

Demand Side Management refers to, for the purposes of this IRP, utility programs, including tariffs, which encourage reduced energy consumption, either at times of peak consumption or throughout the day/year. Programs or tariffs that reduce consumption at the peak are demand response (DR) programs, while round-the-clock measures are energy efficiency (EE) programs. The distinction between peak demand reduction and energy efficiency is important, as the solutions for accomplishing each objective are typically different, but not necessarily mutually exclusive.

6.4.2 Demand Response

Peak demand, measured in megawatts (MW), can be thought of as the amount of power used at the time of maximum power usage. In AEP’s respective East (PJM) zone, this maximum (System peak) is likely to occur on the hottest summer weekday of the year, in the late afternoon. This happens as a result of the near-simultaneous use of air conditioning by the majority of customers, as well as the normal use of other appliances and (industrial) machinery. At all other times during the day, and throughout the year, the use of power is less.

As peak demand grows with the economy and population, new capacity must ultimately be built. To defer construction of new power plants, the amount of power consumed at the peak must be reduced. This can be addressed several ways via both “active” and “passive” measures:

Interruptible loads. This refers to a contractual agreement between the utility and a large consumer of power, typically an industrial customer. In return for reduced rates, an industrial customer allows the utility to “interrupt” or reduce power consumption during peak periods, freeing up that capacity for use by other consumers.

Direct load control. Very much like an (industrial) interruptible load, but accomplished with many more, smaller, individual loads. Commercial and residential customers, in exchange for monthly credits or payments, allow the energy manager to deactivate or cycle discrete appliances, typically air conditioners, hot water heaters, lighting banks, or pool pumps during periods of peak demand. These power interruptions can be accomplished through radio signals that activate switches or through a digital “smart” meter that allows activation of thermostats and other control devices.

Time-differentiated rates. Offers customers different rates for power at different times during the year and even the day. During periods of peak demand, power would be relatively more expensive, encouraging conservation. Rates can be split into as few as two rates (peak and off-peak) and to as often as 15-minute increments known as “real-time pricing”. Accomplishing real-time pricing requires digital (smart) metering.



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Energy Efficiency measures. If the appliances that are in use during peak periods use less energy to accomplish the same task, peak energy requirements will likewise be less. This represents a “passive” demand response.

Line loss mitigation. A line loss results during the transmission and distribution of power from the generating plant to the end user. To the extent that these losses can be reduced, less energy is required from the generator.

What may be apparent is that, with the exception of Energy Efficiency measures, the amount of power consumed is not typically reduced. Less power is consumed at the peak, but to accomplish the same amount of work, that power will be consumed at some point during the day. If rates encourage someone to avoid running their dishwasher at four, they will run it at some other point in the day. This is also referred to as load shifting.

6.4.3 Energy Efficiency

EE measures save money for customers billed on a “per kilowatt-hour” usage basis. The trade-off is the reduced utility bill for any up-front investment in a building/appliance/equipment modification, upgrade, or new technology. If the consumer feels that the new technology is a viable substitute and will pay him back in the form of reduced bills over an acceptable period, he will adopt it.

EE measures include efficient lighting, weatherization, efficient pumps and motors, efficient HVAC infrastructure, and efficient appliances, most commonly. Often, multiple measures are bundled into a single program that might be offered to either residential or commercial/industrial customers.

EE measures will, in all cases, reduce the amount of energy consumed but may have limited effectiveness at the time of peak demand. Energy Efficiency is viewed as a readily deployable, relatively low cost, and clean energy resource that provides many benefits. According to a March 2007 DOE study such benefits include:

Economics: Reduced energy intensity provides competitive advantage and frees economic resources for investment in non-energy goods and services

Environment: Saving energy reduces air pollution, the degradation of natural resources, risks to public health and global climate change.

Infrastructure: Lower demand lessens constraints and congestion on the electric transmission and distribution systems

Security: Energy Efficiency can lessen our vulnerability to events that cut off energy supplies



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However, market barriers to Energy Efficiency exist for the customer/participant.

Market Barriers to Energy Efficiency

High First Costs Energy-efficient equipment and services are often considered “high-end” products and can be more costly than standard products, even if they save consumers money in the long run.

High Information or Search Costs

It can take valuable time to research and locate energy efficient products or services.

Consumer Education Consumers may not be aware of energy efficiency options or may not consider lifetime energy savings when comparing products.

Performance Uncertainties

Evaluating the claims and verifying the value of benefits to be paid in the future can be difficult.

Transaction Costs Additional effort may be needed to contract for energy efficiency services or products.

Access to Financing Lending industry has difficulty in factoring in future economic savings as available capital when evaluating credit-worthiness.

Split Incentives The person investing in the energy efficiency measure may be different from those benefiting from the investment (e.g. rental property)

Product/Service Unavailability

Energy-efficient products may not be available or stocked at the same levels as standard products.

Externalities The environmental and other societal costs of operating less efficient products are not accounted for in product pricing or in future savings

Source: Eto, Goldman, and Nadel (1998): Eto, Prahl, and Schlegel (1996); and Golove and Eto (1996)

To overcome many of the participant barriers noted above, a portfolio of programs may often include several of the following elements:

Consumer education

Technical training

Energy audits

Rebates and discounts for efficient appliances, equipment and buildings

Industrial process improvements

The level of incentives (rebates or discounts) offered to participants is a major determinant in the pace of market transformation and measure adoption.

Additionally, the speed with which programs can be rolled out also varies with the jurisdictional differences in stakeholder and regulatory review processes. The lead time can easily exceed a year



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for getting programs implemented or modified. This IRP begins adding demand-side resources in 2011 that are incremental to approved or mandated programs.

6.4.4 Distributed Generation

Distributed generation refers to (typically) small scale customer-sited generation downstream of the customer meter. Common examples are combined heat and power (CHP), residential solar applications, and even wind. Currently, these sources represent a negligible component of demand-side resources as even with available Federal tax credits, they are typically not economically justifiable.

6.4.5 Integrated Voltage/VaR Control

IVVC provides all of the benefits of power factor correction, voltage optimization, and condition-based maintenance in a single, optimized package. In addition, IVVC enables conservation voltage reduction (CVR) on a utility’s system. CVR is a process by which the utility systematically reduces voltages in its distribution network, resulting in a proportional reduction of load on the network. A 1% reduction in voltage typically results in a 0.5% to 0.7% reduction in load.

Exhibit 6-8: Integrated Voltage/VaR Control

6.4.6 Energy Conservation

Often used interchangeably with efficiency, conservation results from foregoing the benefit of electricity either to save money or simply to reduce the impact of generating electricity. Higher rates for electricity typically result in lower consumption. Inclining block rates, or rates that increase with usage, are rates that encourage conservation.



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7.0 Evaluating DR/EE Impacts for the 2010 IRP

7.1 Demand Response/Energy Efficiency Mandates and Goals

The Energy Independence and Security Act of 2007 (“EISA”) requires, among other things, a phase-in of lighting efficiency standards, appliance standards, and building codes. The increased standards will have a discernable effect on energy consumption. Additionally, legislative and/or regulatory mandated levels of demand reduction and/or energy efficiency attainment, subject to cost effectiveness criteria, are in place in Ohio, Indiana and Michigan in the AEP-East Zone. The Ohio standard, if cost-effective criteria are met, will result in installed efficiency measures equal to over 20 percent of all energy otherwise supplied by 2025. Indiana’s standard achieves installed efficiency reductions of 13.90% in 2020 while Michigan’s standard achieves 10.55%. Virginia has a voluntary 10% by 2020 target. While no mandate currently exists in Kentucky, KPCo has offered DR/EE programs to customers since the mid-1990’s.

As identified in this document and in the Company’s 2010 Corporate Accountability Report, AEP has internally committed to system-wide peak demand reductions of 1,000 MW by year-end 2012 and energy reductions of 2,250 GWh, approximately 60-65% of which is in the AEP-East zone.

7.2 Current DR/EE Programs

As of June 1, 2010, active energy efficiency programs exist in Kentucky, Ohio, Michigan, with additional programs filed in Indiana and West Virginia. Demand response programs, consisting of interruptible tariffs, time differentiated rates, and load control, are currently being offered. The demand and energy impacts of the installed programs (as of March 31, 2010) are shown in Exhibit 7-1. Appendix G lists annual energy efficiency programs and demand reduction forecasts by operating company, by year.

Exhibit 7-1: AEP-East Embedded DR/EE Programs

Energy Reductions (GWh)Energy

Efficiency Interuptible ATOD Total Energy EfficiencyOhio 38 140 0 178 305APCo 0 14 107 121 0I&M 2 258 0 260 8

Kentucky 3 0 0 3 4AEP-East 43 412 107 562 317

Installed Demand Reductions (MW)




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7.2.1 gridSMART Smart Meter Pilots

Smart meter pilots are underway in Indiana and Ohio. As of June 1st, 2010, nearly 200,000 customers have been equipped with the new meters. The meters allow for time-differentiated pricing which should result in more efficient customer use of electricity and peak usage reductions.

AEP’s first gridSMART pilot program began in 2009 in South Bend, Indiana. The year-long South Bend pilot involved approximately 10,000 meters and was to end after the 2009 cooling season, but it has been extended to include the 2010 cooling season because of some early technical problems.

A larger and more comprehensive gridSMART demonstration project involves 110,000 customers in central Ohio. Paid for in part with a $75M grant from the DOE, the $150M project will include smart meters, distribution automation equipment to better manage the grid, community energy storage devices, smart appliances and home energy management systems, a new cyber security center, PHEV (Plug-in/hybrid electric vehicle) demonstrations, and installation of utility-activated control technologies that will reduce demand and energy consumption without requiring customers to take action. This last technology is known as such as Integrated Voltage VaR Control (IVVC), a form of voltage control that allows the grid to operate more efficiently. In IVCC, sensors and intelligent controllers monitor load flow characteristics and direct controls on capacitor and voltage regulating equipment to optimize power factor (Var flow) and voltage levels. Power factor optimization improves energy efficiency by reducing losses on the system. Voltage optimization can allow a reduction of system voltage that still maintains minimum levels needed by customers, enabling consumers to use less energy without any changes in behavior or appliance efficiencies. Early results indicate a range of 0.5% to 1% of energy demand reduction for a 1% voltage reduction is possible.

The results of these pilots will greatly inform the impacts assigned to larger roll-outs of these meters and related projects such as IVVC, should they ultimately be approved. It is still unknown how much deployment of these meters will change customer consumption patterns relative to traditional meters. As these behaviors become discernible and quantifiable, their effects will be incorporated into future load forecasts and IRPs.

7.3 Assessment of Achievable Potential

The amount of Energy Efficiency and Demand Response that are available are typically described in three buckets: technical potential, economic potential, and achievable potential. For states that do not have mandates in place, DR/EE savings were developed using an achievable potential target (Exhibit 7-2).



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Exhibit 7-2: Achievable versus Technical Potential (Illustrative)

Technical Efficiency Potential

Economic Efficiency Potential

Achievable Efficiency Potential


Briefly, the technical potential encompasses all known efficiency improvements that are possible, regardless of cost, and thus, cost-effectiveness. The logical subset of this pool is the economic potential. Most commonly, the total resource cost test is used to define economic. This compares the avoided cost savings achieved over the life of a measure/program with its cost to implement it, regardless of who paid for it. The third set of efficiency assets is that which is achievable.

Of the total potential, only a fraction is achievable and only then over time due to the existence of market barriers. How much effort and money is deployed towards removing or lowering the barriers is a decision made by state governing bodies.

States with legislative or regulatory requirements universally require that these requirements be met economically and provide for “off ramps” if or when pursing the goals no longer meets that criterion. “Economic potential” is estimated to be in the 20-25% range of total consumption. The “achievable” range is a fraction of the economical range. This achievable amount must be further split between what can or should be accomplished with utility-sponsored programs and what should fall under codes and standards. Both amounts are represented in this IRP as reductions to what would otherwise be the load forecast.

7.4 Utility-sponsored DSM modeling/forecasting

Two sources were used as the basis for the analysis in this IRP. The first source is an AEP Measures Database that was specifically developed for AEP and its jurisdictions as part of its DSMore software package. DSMore, an industry-standard software tool, analyzes DR/EE programs



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and produces test results in line with DR/EE industry standards. The AEP Measures Database was used to determine which measures would be modeled in the current IRP. The second is a national energy efficiency study published by the Electric Power Research Institute (EPRI) in January of 2009. This study defines realistically achievable EE target levels. It estimates a cumulative achievable target of 3.3% EE savings by 2020 relative to a baseline forecast which includes the effects of the increased standards required in EPAct 2007.

7.4.1 DSM Proxy Resources

The DSMore Measures Library was used to find viable measures by Residential and Commercial class for the IRP. Measures were organized into groups and then evaluated based on their Total Resource Cost Test (TRC) scores. The TRC measures the net costs of a EE program as a resource option based on the total costs of the program, including both the participant’s and the utility’s costs. Aggregate blocks were considered viable and chosen for optimization modeling only if their TRC scores were above 1.00 except for Residential Low and Moderate Income Weatherization. Because these programs are typically required in jurisdictions where energy efficiency is being implemented, its costs and impacts were included outside of the optimization process. As such, the following measure blocks were chosen.

Exhibit 7-3: DSM Proxy Resources Costs

Measure Levelized Resource Cost

$/kWh6

Levelized Program Cost

$/kWh1

TRC Score

C& I Lighting .059 .033 1.05

C&I Pumps & Motors .040 .023 1.53

Residential Lighting .033 .019 1.86

Residential Water Heating

.034 .019 2.39

Residential Low Income .070 .070 0.86

C&I Demand Response7 N/A N/A 1.8

IVVC8 .034-.047 .034-.047 2.1-2.5


These blocks served as proxy resources for the actual programs that will, over time, be implemented. The blocks have individual characteristics or load shapes. It is desirable that, in

6 Non-discounted 7 Assumes no energy savings from demand interruptions 8 Blocks are non-homogeneous



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aggregate, the blocks will have similar characteristics to what eventually gets implemented so that the remainder of the supply-side optimization is accomplished with reasonably accurate demand-side interrelationships.

7.4.2 DSM Levels

Energy usage and energy savings amounts for states that did not have pre-existing mandates were made based on EPRI’s January 2009 study. The EPRI study, Assessment of Achievable Potential from Energy Efficiency and Demand Response Programs in the U.S., "documents the results of an exhaustive study to assess the achievable potential for energy savings and peak demand reduction from [utility-sponsored] energy efficiency and demand response programs." EPRI further defines the "achievable potential" as an estimated range of savings attainable through programs that encourage adoption of energy efficient technologies, taking into consideration technical, economic, and market conditions. The study differentiates what these programs can achieve prospectively from what may occur through the natural adoption of efficiency by consumers, either through preferences or codes and standards. The EPRI study provides a useful basis for assigning realistic levels of energy efficiency and demand response in lieu of jurisdiction-specific studies as well as a basis for assessing jurisdiction-specific study results which are typically stated as a range of possible outcomes. It is noteworthy that the mandates in Ohio and Indiana exceed what EPRI has determined is realistic or even possible by 2020. While conflicting, this outcome is possible if the jurisdictions involved are willing to exceed the funding levels envisioned as maximums by EPRI; it is on this basis that mandates were assumed to be met through 2020.

Exhibit 7-4: Energy Efficiency Impacts

Energy Efficiency Standards - Relative Impact

90,000

95,000

100,000

105,000

110,000

115,000

120,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

AE

P-E

ast R

eta

il S

ale

s (G

Wh

)

Forecast Gross Ohio Indiana Michigan EPRI Max EPRI Realistic

3.3%

5.0%

12.8%Illustrative - Mandates do not apply System-wide




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The use of these proxy resources is necessary to model supply-side and demand-side resources within the same optimization process. In no way does this process imply that these programs, in their current form and composition must be done in equal measure and in all jurisdictions. All states are different and may have specific rules regarding the ability of C&I customers to “opt out” of utility programs, influencing the ultimate portfolio mix. Some states have a collaborative process that can greatly influence the tenor and composition of a program portfolio. These blocks provide a reasonable proxy for demand-side resources within the context of an optimization model.

7.5 Validating Incremental DR/EE resources

7.5.1 Energy Efficiency

Energy Efficiency resource blocks were made available within the Strategist model with annual constraints by program and in total. These constraints keep the resource modeling process from selecting DR/EE resources faster than is practical in non-mandated states. The result of the constraints is a roll out of programs that is consistent with the EPRI realistically achievable level of demand side resources.

Since the blocks were prescreened for cost-effectiveness, this process merely validates the incremental resources within the supply optimization. As a practical matter, actual EE programs are likely to contain elements of many of these programs but not match the blocks exactly. However, for the purposes of validating the cost-effectiveness of demand options, and quantifying the benefits relative to supply options, the proxy demand resources are suitable.

Exhibits 7-5 through 7-7 show the net forecast with relevant benchmarks. The forecasted DSM levels exceed the EPRI realistically achievable level due to aggressive requirements in Ohio, Michigan and Indiana.



71

Exhibit 7-5: AEP -East Energy Efficiency Program Assumptions

90,000

95,000

100,000

105,000

110,000

115,000

120,000

125,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Fo

reca

st E

ner

gy

Req

uir

emen

ts (

GW

h)

Gross ForecastRealistically AchievableNet ForecastForecast InstalledMaximum Achievable(EPRI) Economic EE Potential


Results:

By 2020, as a result on energy efficiency programs, peak demand is reduced by 873 MW in the AEP-East zone; consumption is reduced by 5,602 GWh.

7.5.2 Demand Response

The demand response resource blocks were made available within the Strategist model with annual constraints by program and in total. These resources are incremental to the tariff-based demand response that is currently in place. The results are consistent with levels for demand response in the EPRI study.

Currently, given the extensively long capacity position in AEP-East, the addition of incremental DR, while having value relative to PJM, may have limited value to the AEP-East System given the current cap limitation in the supplementary auction of 1,300 MW. AEP’s inability to realize the full PJM value might hinder cost recovery in some or all jurisdictions. However, incremental DR may include the added flexibility to effect peak reductions at the Operating Companies, providing desirable concomitant value within the AEP-East System Pool. Additionally, demand response capabilities are being aggressively cultivated by FERC, RTOs, and some states. Given that background, and uncertainty surrounding potential EPA HAP rules, it is reasonable to continue pursuit of a robust demand response capability which would include (AEP customer) assets that are currently committed to PJM through independent third-party curtailment service providers (CSPs).



72

Exhibit 7-6: AEP -East Demand Response Assumptions

AEP-East 2010 IRP Demand Response Assumptions

0

200

400

600

800

1,000

1,200

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Dem

and

Res

po

nse

(M

W)

Incremental

Current


7.5.3 IVVC

IVVC blocks varied in cost effectiveness. Strategist was able to pick the most promising project blocks first and add subsequent blocks when it was economical to do so. In the AEP-East System, blocks became economic beginning in 2014. Five of the available seven blocks were ultimately selected.



73

Exhibit 7-7: AEP -East IVV Response Assumptions

106,000

108,000

110,000

112,000

114,000

116,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

AEP E

ast Ret

ail Sal

es (GW

h)

Gross Forecast

IVV

0.4%


7.6 Discussion and Conclusion

The assumption of aggressive peak demand reduction and energy efficiency achievement reflect not only legislative and regulatory mandated levels of DR/EE in Indiana, Ohio, Michigan, Oklahoma and Texas but AEP’s sytem-wide commitment to demand-side resources in other jurisdictions.

The amount of DR/EE included in this Plan is higher than past IRP plans have included. There are a few reasons why this is valid:

Mandates at the state and potentially at the federal level will encourage adoption of demand side resources at a pace higher than would have been reasonably forecast in the past. Indiana enacted a high mandate this year which requires cumulative energy savings of 13.9% by 2020.

Increased awareness and acceptance of the purported link between global climate change and the consumption of fossil fuels will drive increased adoption of conservation measures, independent of economic benefit.

Increased interest in demand response from the introduction of emergency capacity programs from PJM. Because AEP-East has historically not been able to count the demand assets of customers who participate in the PJM program, the Company seeks to broaden its interruptible tariffs to accommodate customers who have previously not been eligible, primarily because of size.

In states without existing legislative or regulatory mandates, the level of DR/EE is consistent with EPRI’s “realistically achievable” levels. Where these levels are exceeded in states with mandates, it is reasonable to expect compliance with those mandates, albeit at potentially high costs.

The mechanism for regulatory cost recovery and the appetite for utility-sponsored DR/EE is formalized through the legislative and ratemaking processes in the various jurisdictions in which AEP



74

operates, the amount and type of DR/EE programs will likely change by jurisdiction to reflect the environment. Executing this plan will enable AEP to fulfill its system-wide commitment of 1,000 MW of demand reduction capability and 2,250 GWh of energy efficiency by 2012.

The following Exhibit 7-8 summarizes the AEP-East EE assumptions for the 2010 IRP. The data is split by “Net” and “Installed”. “Installed” indicates the annualized impacts of DSM measures at the time of installation while “Net” reflects the expected impact. It is less than the installed impact due to assumptions about the timing of the installation (partial year savings), measure fade (measures failing and not being replaced) and “snap back” (the use of saved energy for other purposes).

Installation of these measures is predicated on securing adequate cost recovery. For this planning cycle, it is assumed that such recovery would be forthcoming. For the 10 year planning horizon, this level of DSM still closely matches the EPRI Realistically Achievable.



75

Exhibit 7-8: Incremental Demand-Side Resources Assumption Summary

GWh MW GWh MW2010 233 38 91 162011 900 149 683 1072012 1,592 266 1,266 2002013 2,385 404 1,897 3042014 3,294 563 2,560 4162015 4,249 708 3,215 5052016 5,091 844 3,676 5732017 5,971 988 4,069 6312018 6,887 1,136 4,408 6802019 8,383 1,392 4,967 7682020 9,487 1,593 5,602 873

GWh MW GWh MW2010 0 0 0 02011 0 0 0 02012 0 0 0 02013 0 0 0 02014 136 20 136 202015 253 53 253 532016 338 70 338 702017 423 88 423 882018 509 105 509 1052019 509 106 509 1062020 509 105 509 105

GWh MW GWh MW2010 0 0 0 02011 0 100 0 1002012 0 200 0 2002013 0 350 0 3502014 0 500 0 5002015 0 600 0 6002016 0 600 0 6002017 0 600 0 6002018 0 600 0 6002019 0 600 0 6002020 0 600 0 600

GWh MW GWh MW2010 233 38 91 162011 900 249 683 2072012 1,592 466 1,266 4002013 2,385 754 1,897 6542014 3,429 1,084 2,696 9362015 4,502 1,361 3,468 1,1582016 5,429 1,514 4,015 1,2442017 6,394 1,676 4,493 1,3192018 7,395 1,842 4,917 1,3852019 8,891 2,098 5,475 1,4742020 9,996 2,298 6,111 1,578

Installed NetEnergy Efficiency

IVVCInstalled Net

Demand ResponseInstalled Net

Total Incremental DSMInstalled Net




76



77

8.0 Fundamental Modeling Scenarios

8.1 Modeling and Planning Process—An Overview

A chart summarizing the IRP planning process, identifying the fundamental input requirements, major modeling activities, and process reviews and outputs, is presented in Exhibit 8-1. Given the diverse and far-reaching nature of the many elements as well as participants in this process, it is important to emphasize that this planning process is naturally a continuous, evolving activity.

In general, assumptions and plans are continually reviewed and modified as new information becomes available. Such continuous analysis is required by multiple disciplines across AEP to ensure that: market structures and governances, technical parameters, regulatory constructs, capacity supply, energy adequacy and operational reliability, and environmental mandate requirements are constantly reassessed to ensure optimal capacity resource planning.

Further impacting this process are growing numbers of federal and state initiatives that address many issues relating to industry restructuring, customer choice, and reliability planning. Currently, fulfilling a regulatory obligation to serve native load customers (including Ohio customers) represents one of the cornerstones of this 2010 AEP-East IRP process. Therefore, as a result, the “objective function” of the modeling applications utilized in this process is the establishment of the least-cost plan, with cost being more accurately described as revenue requirement under a traditional ratemaking construct.

That does not mean, however, that the best or optimal plan is the one with the absolute least cost over the planning horizon evaluated. As discussed in this (and prior) section, other factors–some more difficult to quantify than others–were considered in the determination of the AEP-East Integrated Resource Plan (IRP). To challenge the robustness of the Plan, sensitivity analyses were performed to address these factors.

8.2 Methodology

The IRP process aims to address the long-term “gap” between resource needs and current resources (Section 5). Given the various assets and resources that can satisfy this expected long-term gap, a tool is needed to sort through the myriad of potential combinations and return an optimum solution–or portfolio–subject to constraints. Strategist 9 is the primary modeling application used by AEP for identifying and ranking portfolios that address the gap between needs and current available resources. Given the set of proxy resources–both supply and demand side–and a scenario of economic conditions that include fuel prices, capacity costs, energy costs, effluent prices including CO2, and demand, Strategist will return all combinations of the proxy resources (portfolios) that meet the resource need. The portfolios are ranked on the basis of cost, or cumulative present worth (CPW), of the resulting stream of revenue requirements. The least cost option was considered the initial “optimum” portfolio for that unique input parameter scenario.

9 A proprietary long-term resource optimization tool of Ventyx - an ABB company - utilized extensively in the utility industry for over two decades.



78

Exhibit 8-1: IRP Modeling and Planning Process Flow Chart


Inte

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79

8.3 Key Fundamental Modeling Pricing Scenarios

This section includes excerpts from the “Long Term Forecast 2010-2030: Consumer Choice: A Time to Choose, 2H-2009” prepared by AEPSC’s Strategic & Economic Analysis (SEA) organization and issued February 2010.

The AEP-SEA long-term power sector suite of commodity forecasts are derived from the Aurora model. Aurora is a fundamental production-costing tool that is driven by inputs into the model, not necessarily past performance. AEP-SEA models the eastern synchronous interconnect and ERCOT using Aurora. Fuel and emission forecasts established by AEP Fuel, Emissions and Logistics, are fed into Aurora. Capital costs for new-build generating assets by duty type are vetted through AEP Engineering Services. The CO2 forecast is based on assumptions developed by AEP Strategic Policy Analysis.

Exhibit 8-2 shows the AEP-SEA process flow for solution of the long-term (power) commodity forecast. The input assumptions are initially used to generate the output report. The output is used as “feedback” to change the base input assumptions. This iterative process is repeated until the output is congruent with the input assumptions (e.g., level of natural gas consumption is suitable for the established price and all emission constraints are met).

Exhibit 8-2: Long-term Forecast Process Flow

Input Output

Fuel Forecast

Load Forecast

Emissions Forecast

Capital Cost Forecast

Generate ReportEmission Totals Fuel Burn Totals

Market Prices

Longterm Capacity Expansion

Annual Dispatch

Emission Retrofits

Recycle

Source: AEP SEA

In this report, four distinct scenarios were developed: the “Reference Case”, “Business As Usual (BAU) Case”, “Stagnation”, and “Altruism Case”. The scenarios are described below:

Reference – The point of the label “Reference” is not because it is the most likely outcome. It is labeled Reference because it represents what we have typically done in the company – use Moody’s Economy.com as the economic outlook. As compared to previous reference cases, the start of carbon policies have been moved up to 2014 versus 2015, indicating an increased likelihood of a



80

policy. The carbon treatment policy follows a “Waxman-Markey” like policy, except starting in 2014 versus 2012.

Business As Usual (BAU) – As the title of this case suggests, it assumes there is no change from 2009. This includes no change in environmental policies such as carbon. The economic outlook in this scenario is identical to the Reference economic profile other than there is no economic impact observed in 2014 due to carbon policies. This scenario is probably the least likely given that nothing changes, but it certainly is the easiest to conceive because everything is known.

Stagnation – Concerns of rising government debt and no clear path for the transformation of the economy from less consumer driven results in a stagnated economy similar to Japan’s experience. Much like Japan, the country continues to prop up insolvent banks. Optimistically, the U.S. will react faster and remember lessons learned so that stagnation lasts only five years versus Japan’s decade plus.

Altruism – This scenario is the hardest to imagine and construct. There is a united front across the majority of the world for the reduction of carbon. There is one carbon price accepted by all so no major wealth transfers occur. If this assumption did not occur, we could see mass economic shifting as corporations could move to regions that had no carbon policies. Societies across the world take on the problem and develop a moral backing in order to absorb the increased cost and the sacrifices needed to achieve the targets. In the U.S., this cost will come in the form of continued production tax credits, increased CO2 costs and increased fossil fuel costs due to increased environmental constraints for drilling and mining.

The relationship among commodity prices under the different economic scenarios is shown in Exhibit 8-3. Forecasts of particular importance include coal prices, natural gas, CO2, and on-peak and off-peak power prices. Because commodity price forecasts are considered business sensitive information, the comparisons are made using an index, with the Reference Case 2010 price set as 1.0.



81

Exhibit 8-3 Commodity Price Forecast by Scenario

CO2 Price Index (Reference Case 2014 = 1.0)

-

1.00

2.00

3.00

4.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Reference BAU Stagnation Altruism

No CO2 cost in BAU Case


Nat Gas (TCO Delivered) Price Index (Reference Case 2010 = 1.0)

-

1.00

2.00

3.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030



Power On-Peak AEP-PJM Hub Price Index (Reference Case 2010 = 1.0)

-

1.00

2.00

3.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030



Power Off-Peak AEP-PJM Hub Price Index (Reference Case 2010 = 1.0)

-

1.00

2.00

3.00

4.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030



Coal (CAPP) Price Index (Reference Case 2010 = 1.0)

-

1.00

2.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030



Coal (PRB 8800) Price Index (Reference Case 2010 = 1.0)

-

1.00

2.00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030





82



83

9.0 Resource Portfolio Modeling

9.1 The Strategist Model

The Strategist optimization model served as the empirical calculation basis from which the AEP-East zonal capacity requirement evaluations were examined and recommendations were made. As will be identified, as part of this iterative process, Strategist offers unique portfolios of resource options that can be assessed not only from a discrete, revenue requirement basis, but also for purposes of performing additional risk analysis outside the tool.

As its objective function, Strategist determines the regulatory least-cost resource mix for the generation (G) system being assessed.10 The solution is bounded by user-defined set of resource technologies, commodity pricing, and prescribed sets of constraints.

Strategist develops a discrete macro (zone-specific) least-cost resource mix for a system by incorporating a variety of expansion planning assumptions including:

Resource alternative characteristics (e.g., capital cost, construction period, project life).

Operating parameters (e.g. capacity ratings, heat rates, outage rates, emission effluent rates, unit minimum downturn levels, must-run status, etc.) of existing and new units.

Unit dispositions (retirement/mothballing).

Delivered fuel prices.

Prices of external market energy and capacity as well as SO2, NO

X, and CO

2 emission

allowances.

Reliability constraints (in this study, minimum reserve margin targets).

Emission limits and environmental compliance options.

These assumptions, and others, are considered in the development of an integrated plan that best fits the utility system being analyzed. Strategist does not develop a full regulatory cost-of-service (COS) profile. Rather, it typically considers only (G)-COS that changes from plan-to-plan, not fixed embedded costs associated with existing generating capacity that would remain constant under any scenario. Likewise, transmission costs are included only to the extent that they are associated with new generating capacity, or are linked to specific supply alternatives. In other words, generic (nondescript or non site-specific) capacity resource modeling would typically not incorporate significant capital spends for transmission interconnection costs.

Specifically, Strategist includes and recognizes in its “incremental (again, largely (G)) revenue requirement” output profile:

Fixed costs of capacity additions, i.e., carrying charges on capacity and associated transmission (based on a weighted average AEP system cost of capital), and fixed O&M;

Fixed costs of any capacity purchases;

Program costs of DR/EE alternatives

10 Strategist also offers the capability to address incremental transmission (“T”) options that may be tied to evaluations of certain generating capacity resource alternatives.



84

Variable costs associated with the entire fleet of new and existing generating units (developed using its probabilistic unit dispatch optimization engine). This includes fuel, purchased energy, market replacement cost of emission allowances, and variable O&M costs;

Market revenues from external energy transactions (i.e. Off-System Sales) are netted against these costs under this ratemaking/revenue requirement format.

In order to create a full regulatory cost of service, additional cost were developed to capture the revenue requirement impact from the embedded fixed cost of AEP’s existing generation, transmission and distribution systems (i.e. G/T/D costs). These additional G/T/D revenue requirements were added to the incremental revenue requirements developed by Strategist to create a full regulatory cost of service.

In the PROVIEW module of Strategist, the least-cost expansion plan is empirically formulated from potentially hundreds of thousands of possible resource alternative combinations created by the module’s chronological dynamic programming algorithm. On an annual basis, each capacity resource alternative combination that satisfies various user-defined constraints (to be discussed below) is considered to be a “feasible state” and is saved by the program for consideration in following years. As the years progress, the previous years’ feasible states are used as starting points for the addition of more resources that can be used to meet the current year’s minimum reserve requirement. As the need for additional capacity on the system increases, the number of possible combinations and the number of feasible states increases exponentially with the number of resource alternatives being considered.

9.1.1 Modeling Constraints

The model’s algorithm has the potential for creating such a vast number of alternative combinations and feasible states; it can become an extremely large computational and data storage problem, if not constrained in some manner. The Strategist model includes a number of input variables specifically designed to allow the user to further limit or constrain the size of the problem. There were numerous other known physical and economic issues that needed to be considered and, effectively, “constrained” during the modeling of the long-term capacity needs so as to reduce the problem size within the tool.

Maintain an AEP-PJM installed capacity (ICAP) minimum reserve margin of roughly 15.5% per year as represented in the east region’s “going-in” capacity position (which itself assumed a PJM Installed Reserve Margin (IRM) of 15.5% throughout the 2011/2012 planning year and 15.3% effective 2013/2014 and through the remaining years of the planning period).

All generation installation costs represent AEP-SEA view of capacity build prices that were predicated upon information from AEP Generation Technology Development.

Under the terms of the NSR Consent Decree, AEP agreed to annual SO2 and NOX emission limits for its fleet of 16 coal-fueled power plants in Indiana, Kentucky, Ohio, Virginia and



85

West Virginia. These emission limits were met by adjusting the dispatch order of these units during Strategist’s economic dispatch modeling.

9.2 Resource Options/Characteristics and Screening

9.2.1 Supply-side Technology Screening

There are many variants of available supply and demand-side resource types. It is a practical limitation that not all known resource types are made available as modeling options. A screening of available supply-side technologies was performed with the optimum assets made subsequently available as options. Such screens for supply alternatives were performed for each of the major duty cycle “families” (baseload, intermediate, and peaking).

The selected technology alternatives from this screening process do not necessarily represent the optimum technology choice for that duty cycle family. Rather, they reflect proxies for modeling purposes.

Other factors will be considered that will determine the ultimate technology type (e.g. choices for “peaking” technologies: GE frame machines “E” or “F”, GE LMS100 aeroderivative machines, etc.). The full list of screened supply options is included in Appendix C.

Based on the established comparative economic screenings, the following specific supply alternatives were modeled in Strategist for each designated duty cycle:

Peaking capacity was modeled as blocks of eight, 82 MW GE-7EA Combustion Turbine units (summer rating of 78.5 MW x 8 = 628 MW), available beginning in 2019. Note: No more than one block could be selected per year.

Intermediate capacity was modeled as single natural gas Combined Cycle (2 x 1 GE-7FB with duct firing platform) units, each rated 650 MW (613 MW summer) available beginning in 2019.

Baseload capacity burning eastern bituminous coals was modeled. The potential for future legislation limiting CO2 emissions was considered in selecting the solid fuel baseload capacity alternatives. Two solid fuel alternatives were made available to the model: 526 MW Ultra Supercritical PC unit (summer rating of 520 MW) where the unit is

installed with chilled ammonia carbon capture and storage (CCS) technology that would capture 90% of the unit’s CO2 emissions. This option could be added beginning in 2020.

776 MW Integrated Gasification Combined Cycle (IGCC) “H” Class unit equipped with CCS technology that would reduce 90% of the unit’s carbon emissions. This alternative could be added by Strategist beginning in 2020 and;

In addition, beginning in the year 2022: Strategist could select an 800 MW share of a 1,606 MW nuclear, Mitsubishi Heavy

Industries (MHI) Advanced Pressurized Water Reactor (771 MW summer)

In order to maintain a balance between peaking, intermediate and baseload capacity resources, only eight Combustion Turbine (CT) units could be added in any year. If the addition of eight CTs



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was not sufficient to meet reliability requirements in a particular year, the model was required to add either intermediate and/or baseload capacity to meet the reliability targets.

9.2.2 Demand-side Alternative Screening

As described in Section 7, eighteen “blocks” of EE programs were available each year to be evaluated in Strategist over the 2011-2015 period. There were also a total of twelve 50 MW blocks of DR that could be added (2-3 per year) over the 2011-2015 period. In addition, there were a total of 7 blocks of Integrated Voltage/Var (IVV) control that could be added over the 2012-2018 period. The economics of the DR/EE/IVV blocks were screened in order to minimize the problem size of the full Strategist optimization. The DR/EE/IVV blocks were evaluated under all of the economic scenarios described in Section 8. The results of this screening analysis showed that 560 MW of EE and 600 MW of DR were selected under all of the economic scenarios. In all economic scenarios, 30 MW to 110 MW of IVV was selected depending on the economic scenario.

9.3 Strategist Optimization

9.3.1 Purpose

Strategist should be thought of as a tool used in the development of potentially economically viable resource portfolios. It doesn’t produce “the answer;” rather, it produces or suggests many portfolios that have different cost profiles under different pricing scenarios and sensitivities. Portfolios that fare well under all scenarios and sensitivities are considered for further evaluation. The optimum, or least-cost, portfolio under one scenario may not be a low-cost, or even a viable portfolio in other scenarios. Portfolio selection may reflect strategic decisions embraced by AEP leadership, including a commitment to DR/EE, renewable resources and clean coal technology. Strategist results, both “optimum” and “suboptimum,” serve as a starting point for constructing model portfolios.

For example, if a scenario dictates an unconstrained Strategist consistently picks a CT option to the point that such peaking capacity is being added in large quantities, a portfolio that substitutes a 650 MW combined cycle plant for eight, 82 MW CTs might be constructed and tested through Strategist to see if the resultant economic answer (i.e., CPW of revenue requirements) is significantly different. Intervening in the algorithm of Strategist to insert some additional practical constraints or conform to an AEP strategy yields a solution that is more realistic and not injuriously more expensive. The optimum or least expensive portfolio under a scenario may have practical limitations that Strategist does not take into full account.

9.3.2 Strategic Portfolios

Strategic decisions that were considered when constructing the underlying AEP-East resource portfolios include:



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Renewable Resources: On an AEP system-wide basis, to achieve 6% of energy sales from renewable energy

sources by 2013, 10% by 2020 and 15% by 2030. Recognition of potential for a Federal RPS and mandatory state RPS in Ohio, Texas,

Michigan, and West Virginia and voluntary RPS in Virginia. Assumptions on “early mover” commitment to these GHG and renewable strategies

Limit exposure to scarce resource pricing. Take advantage of current tax credit for renewable generation. Reduce exposure to potential GHG legislation, as initial mitigation requirements unfold. Plan to be in concert with other CO2/GHG reduction options (offsets, allowances, etc.).

Energy efficiency: Consideration of increased levels of cost-effective DR/EE over previous resource planning cycles reflects additional state mandates, stakeholder desires for such measures, as well as regulator willingness in the form of revenue recovery certainty.

As will be described, additional sensitivities were then contemplated to determine the effects of the optimum portfolios, as well as to build additional portfolios. The build plans that were suggested by Strategist under the various scenarios and sensitivities are described in the following sections.

9.4 Optimum Build Portfolios for Four Economic Scenarios

9.4.1 Optimal Portfolio Results by Scenario

Given the four fundamental pricing scenarios developed by AEP-FA from Section 8.3, as well as the modeling constraints and certain planning commitments, Strategist modeling was used to develop the incremental portfolios identified in Exhibit 9-1:



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Exhibit 9-1: Model Optimized Portfolios under Various Power Pricing Scenarios Business As Usual Case Stagnation Case Reference Case Altruism Case

Optimization Optimization Optimization Optimization201020112012201320142015201620172018

20198 - 82 MW CTs, 1 - 650 MW CC

8 - 82 MW CTs, 1 - 650 MW CC

8 - 82 MW CTs, 1 - 650 MW CC

8 - 82 MW CTs, 1 - 650 MW CC

20202021 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs202220232024 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs20252026 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs202720282029 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs 8 - 82 MW CTs2030

Total East System Cost2010-2035 CPW ($M) 119,139,548 123,097,624 134,133,179 145,370,495

2010 - 2030 Levelized ($/MWh) 82.85 88.35 95.48 103.68

Number of Units AddedCT 32 40 40 40CC 1 1 1 1PC 0 0 0 0

IGCC 0 0 0 0Nuclear 0 0 0 0

Total Capacity (MW) 3,274 3,930 3,930 3,930Total Optimized DR/EE/IVV (MW Reduced) 1,185 1,265 1,265 1,265


Notes:

1) Because Renewable assets and a base level of incremental DR/EE/IVV are included in all portfolios,

Strategist did not represent them as incremental resources within these comparative portfolio views.

2) The total capacity of the supply-side additions assumes that the 540 MW Dresden CC unit would become

operational in April 2013.

3) The IRP planning horizon extends to 2020 as represented by the horizontal line. For modeling purposes

Strategist constructs portfolios through 2030.

9.4.2 Observations: 2019 Combined-cycle Addition

As shown in Exhibit 9-1, all pricing scenarios added a CC unit in 2019. The CC addition is made because of the constraint imposed on the model that allows only a single block of 8 CTs to be added in any one year. Had the model been allowed to add as many CT blocks as economic, an additional block of 8 CTs would have been added in 2019 instead of the CC under all pricing scenarios.



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9.4.3 Additional Portfolio Evaluation

As an extension of the optimal portfolios created under the four pricing scenarios, several additional portfolios were tested, or developed around defined objectives. These portfolios were created with the goal of examining the economics of portfolios created under factors and influences other than commodity prices. These portfolios can be defined as follows:

Retirement Transformation Plan – Accelerate All “Fully” Exposed Unit Retirements to 1/2016 and Retire All “Partially” Exposed Units between 1/2016 and 1/2020

No CCS Retrofits on Existing Units

Alternative Resource Plan - Enhanced Renewables and DR/EE/IVV + Best “Contrary” Nuclear Plan

Green Plan - Alternative Resources Plan + Retirement Transformation Plan

Exhibit 9-2 provides a summary of these portfolios under Reference Case conditions.

Exhibit 9-2: Portfolio Summary Alternative

Retirement No CCS Retrofits on ResourceTransformation Plan Existing Units Plan Green Plan

2009201020112012201320142015

20168 - 165 MW CTs, 1 - 650 MW CC

8 - 82 MW CTs

20178 - 165 MW CTs, 2 - 650 MW CC

20188 - 165 MW CTs, 1 - 650 MW CC

8 - 165 MW CTs, 2 - 650 MW CC

20198 - 165 MW CTs, 2 - 650 MW CC

8 - 165 MW CTs, 1 - 650 MW CC

8 - 82 MW CTs8 - 165 MW CTs, 2 - 650 MW CC

2020

2021 8 - 82 MW CTs1-800 MW Nuke 1-800 MW Nuke

202220232024 8 - 82 MW CTs2025 8 - 82 MW CTs2026 8 - 82 MW CTs 8 - 82 MW CTs2027 8 - 82 MW CTs2028 8 - 82 MW CTs2029 8 - 82 MW CTs 8 - 82 MW CTs2030 8 - 82 MW CTs

Total East System Cost Under Reference Price Scenario2010-2035 CPW ($M) 136,035,511 136,638,030 136,115,947 137,196,444

2010 - 2030 Levelized ($/MWh) 9.72 9.73 9.72 9.83

Number of Units AddedCT 48 32 32 40CC 5 1 1 4

Nuclear 0 0 1 1Total Capacity (MW) 7,186 3,274 4,074 6,680

Total Optimized DSM (MW Reduced) 1,265 1,265 1,703 1,703 Source: AEP Resource Planning

9.4.3.1 “Retirement Transformation” Plan

The objective behind examining this portfolio was to determine the increased cost of a portfolio that accelerated the retirement of all “Fully Exposed” units and the retirement all of the “Partially Exposed” units that were scheduled to receive emission retrofits. In all other cases, several of the Full



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Exposed units had retirement dates that occurred after 2016. In the Retirement Transformation Plan, those retirements that were profiled to occur from 2016 through 2019 as part of the Unit Disposition analysis described in Section 3 were accelerated to January 2016. In addition, the Partially Exposed units were assumed to be retired on the date they were originally profiled as part of the same disposition process to receive emission retrofits.

9.4.3.2 “No CCS Retrofits” Plan

In all other pricing scenarios but Business As Usual, approximately 3,700 MW of existing AEP-East solid-fuel units were assumed to be retrofitted with CCS technology. When CCS retrofits were installed, CO2 “Bonus Allowances” were awarded to AEP to offset the cost of installing the CCS retrofits.11 In this portfolio, the objective was to determine the increased cost of CO2 emission exposure by not performing the CCS retrofits and obtaining the Bonus Allowances. Instead, AEP’s entire solid-fuel generating fleet would be subject to the assumed CO2 emissions cost under each pricing scenario.

9.4.3.3 “Alternative Resource” Plan

The Alternative Resource Plan was created by combining:

Increasing the levels of renewable energy resources and DR/EE/IVV added to the system by a relative magnitude of fifty percent, and;

The “Best” Contrary Nuclear Plan, which was the best “sub-optimal” plan established by Strategist that included a nuclear baseload resource..

The renewable energy targets set for this scenario require that 6% of system-wide energy sales be met with renewable energy resources by 2013, 15 percent (versus 10 percent) by 2020 and 22.5 percent (versus 15 percent) by 2030. The timing of the nuclear unit addition in the Contrary Nuclear Plan was established during the initial optimization analysis as the “optimal” point in time in the early 2020s to add Nuclear baseload capacity.

9.4.3.4 “Green” Plan

The Green Plan was created by combining the Retirement Transformation Plan and the Alternative Resource Plan. The purpose of creating the Green Plan was to test the economics of a portfolio with very low emissions profiles by introducing the accelerated retirement of solid fuel units, increased levels of renewable energy and DR/EE/IVV and the addition of a low emitting nuclear unit.

A summary of the Optimal Portfolio and Additional Portfolio plan’s costs over the full (2010-2035) extended planning horizon, and under the various pricing scenarios is shown in Exhibit 9-3.

11 “Bonus Allowances” designed to incentivize commercial development of CCS technology have been incorporated as part of the House-approved Waxman-Markey Bill as well as comparable Senate legislation currently under discussion.



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Exhibit 9-3: Optimized Plan Results (2010-2035) Under Various Pricing Scenarios

$119,139,548 $123,608,730 $136,014,837 $148,670,225

$126,137,376 $123,097,624 $134,133,179 $145,385,453

$126,137,376 $123,097,624 $134,133,179 $145,385,453

$126,133,852 $123,097,452 $134,123,709 $145,370,495

$124,624,453 $136,035,511 $146,132,185

$124,256,115 $136,638,030 $149,257,679

AEP East 2010-2035 CPW ($000)

137,196,444 $146,776,618''Green Plan"... 'Alternative Resources' Plan (above) + Retire All 'Partially-Exposed' Units by 1/2016 + Retire All 'Partially-Exposed' Units by 1/2020

$127,568,854

136,115,947 146,666,529''Alternative Resources Plan"... Best 'HIGH' Renewable / "Efficiency"' + Best 'Contrary' Nuc

126,602,394

No CCS Retrofits (in lieu of assumed {subsidized} ~5,500 MW by 2020 in 'BASE')

Retirement Transformation Plan...Reflect RETIREMENT of all 'Partially Exposed' Units; 2016-2020

'Altruism' (HIGH Price) Scenario Optimal Plan

'BAU' (No CO2) (LOW Price w/o CO2)Scenario Optimal Plan

'Stagnation' (LOW Price w/ CO2) Scenario Optimal Plan

'REFERENCE' (BASE Price) Scenario Optimal Plan

Pricing Scenario

NO Carbon Legislation / Regulation

World

(Ultimate) Carbon Legislation

"BAU"-(Alt) LOW Proxy-

(No CCS)

"Stagnation" -LOW Proxy- (with CCS*)

"Reference" -BASE Proxy- (with CCS*)

"Altruism" -HIGH Proxy- (with

CCS*)


9.4.4 Market Energy Position of the AEP East Zone

The AEP-East fleet is projected to undergo a change in its operational mix particularly beginning in the year 2015 as older coal units retire. This leaves a smaller number of units available to serve a baseload function. This could expose the AEP LSEs to market prices and would cause them to become, in effect, “price takers” from the market. The probability of this occurring in a potential portfolio is reduced when AEP maintains a minimum net market (energy) position of approximately 10% of its annual energy requirements, or 12,000 GWH. Exhibit 9-4 shows that each of the portfolios evaluated meet this criteria.



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Exhibit 9-4: Annual Energy Position of Evaluated Portfolios

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2009-13 2014-18 2019 2020 2021 2022 2023 2024 2025

Net

Mar

ket Posi

tion, G

Wh

Hybrid Base Optimal Coal Enhanced Renew ables Green


9.4.5 Portfolio Views Selected for Additional Risk Analysis

The following summarizes the six portfolio views as set forth by the discrete AEP East capacity resource modeling performed using Strategist that were analyzed further in the Utility Risk Simulation Analysis (URSA) model described in Section 10.

Reference Pricing Case Optimal Plan (Base Plan)

Business As Usual Pricing Case Optimal Plan (No CO2 Plan)

Retirement Transformation Plan

No CCS on Existing Units Plan

Alternate Resources Plan

“Green Plan”

These resource portfolio options created in Strategist and their revenue requirements offer modeled economic results based on specific, discrete “point estimates” of the variables that could affect these economics. These portfolios were evaluated over a distributed range of certain key variables in URSA, which provided a probability-weighted solution that offers additional insight surrounding relative cost/price risk.



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10.0 Risk Analysis

The six portfolios identified in Section 9 that were selected using Strategist and the Hybrid plan were subjected to rigorous “stress testing” to ensure that none would have outcomes that would be deleterious under a probabilistic array of input variables.

10.1 The URSA Model

Developed internally by AEP Market Risk Oversight, the Utility Risk Simulation Analysis (URSA) model uses Monte Carlo simulation of the AEP East Zone with 1,399 possible futures for certain input variables. The results take the form of a distribution of possible revenue requirement outcomes for each plan. The input variables or risk factors considered by URSA within this IRP analysis were:

Eastern and Western coal prices, natural gas prices, uranium prices, power prices, emissions allowance prices, full requirements loads. steam and combustion units forced out.

These variables were correlated based on historical data.

For each plan, the difference between its mean and its 95th percentile was identified as Revenue Requirement at Risk (RRaR). This represents a level of required revenue sufficiently high that it will be exceeded, assuming that the given plan were adopted, with an estimated probability of 5.0 percent.

Exhibit 10-1 illustrates for one plan, the “Hybrid Plan,” the average levels of some key risk factors, both overall and in the simulated outcomes whose Cumulative Present Value (CPV) revenue requirement is roughly equal to or exceeds the upper bound of Revenue Requirement at Risk. Note that these CPV’s are consistent with the CPW values calculated using the Strategist tool. The table is specific to the Hybrid Plan, but the numbers would be very similar under the other plans. (The particular alternative futures producing the highest levels are not necessarily the same between different plans.)



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Exhibit 10-1: Key Risk Factors – Weighted Means for 2010

Variable Mean Mean Difference % DiffAEP Internal Onpeak Load 16,033 16,024 (8.78) -0.05%AEP Onpeak Power Spot 75.47 82.47 7.00 9.28%CO2 Allowance Spot 25.04 58.24 33.20 132.59%NYM Coal Spot 61.60 65.49 3.89 6.31%Henry Hub Gas Spot 7.94 9.07 1.13 14.23%Uranium Spot 0.81 0.82 0.01 1.23%Steam Units Forced Out 1,668 1,670 1.74 0.10%Combustion Units Forced Out 509.46 510.06 0.60 0.12%

Simulated Outcomes – Hybrid PlanAll Outcomes RRaR-Exceeding Outcomes

Source: AEP Market Risk Oversight

The price of CO2 allowance, spot gas, and on-peak power prices is greater among the RRaR-exceeding outcomes, suggesting that they are critical sources of risk to revenue requirements. The relative difference between that “tail” and mean outcomes are 132.59%, 14.23%, and 9.28%, which is significantly greater than the relative difference of other risk factors.

It might be assumed that the very worst possible futures would be characterized by high fuel and allowance prices and low power prices. But according to the analysis of the historical values of risk factors that underlies this study, such futures have essentially no chance of occurring. Any possible future with high fuel prices would essentially always have high power prices. Likewise the risk factor analysis implies an inverse correlation between NOX allowance prices and some of the other risk factors that determine the tail cases, so that in these tail cases, the average NOX allowance price is actually less than the average across all possible futures.

10.2 Installed Capital Cost Risk Assessment

In order to further scrutinize the six plans under the 1399 possible futures, the impacts of Installed Capital Cost Risk on the URSA results were examined. A six-point capital cost distribution for each of the seven plans was created. (See Exhibit 10-2 for its basis.) In creating the distribution for each plan, the installed capital costs of all types of generating capacity were assumed to be perfectly correlated with each other. The fixed representation of installed capital costs in URSA was removed from each URSA output distribution and the resulting distributions were convolved with the installed capital cost distributions.

Exhibit 10-2: Basis of Installed Capital Cost Distributions

5% 19% 33% 23.67% 14.33% 5%

-15% -7.5% Base 13.33% 27% 40%-10% -5% Base 6.67% 13.33% 20%-15% -7.5% Base 16.67% 33% 50%

Probability of occurrence, Percent Capital Cost Variance:

Solid-fuel UnitsGas-fuel UnitsNuclear Units




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10.3 Results Including Installed Capital Cost Risk

Exhibit 10-3 summarizes the Installed Capital Cost Risk-adjusted results for all six AEP-East plans.

Exhibit 10-3: Risk -Adjusted CPW 2010-2035 Revenue Requirement ($ Millions)

PLAN 50thPercentile

95thPercentile

RevenueRequirement

at RiskNo CO2 119,190 124,965 5,775Base Case 134,174 163,009 28,835Accel Coal Ret 136,092 162,162 26,070No CCS 136,701 168,324 31,623Alt Resc 136,370 162,955 26,585Green 137,424 161,280 23,856


Exhibit 10-3 shows reasonably consistent results across all plans modeled. These comparative results also suggest that, given the fuel/generation diversity of the capacity resource options introduced into the analysis, the relative economic exposure would appear to be small irrespective of the plan selected.

The three lowest-cost plans at the 50th percentile are the No CO2, Base Case, and Accelerated Coal Retirements. However, the lowest cost plans at the Revenue Requirement at Risk are the No CO2, Green, and Accelerated Coal Retirements. While the lowest cost plan at the 95th percentile is the No CO2 plan, keep in mind that the No CO2 plan is not directly comparable to the other plans in that CO2 costs are excluded. The plan was included to point out the expected cost of CO2 legislation on ratepayers. As the exhibit shows, this impact ranges from approximately $15 billion to $40 billion on a net present value basis.

RRaR measures the risk relative to the 50th percentile, or expected, result of a plan. The plan with the least RRaR is not necessarily preferred for risk avoidance. Instead, low values of required revenue at extreme percentiles, such as the 95th, are preferred.

The estimated distributions of revenue required under the seven plans are rather similar. Exhibits 10-4 and 10-5 show the superimposed graphs of all six distribution functions. Exhibit 10-4 shows entire distributions; Exhibit 10-5 shows only the region at or above the 95th percentile.



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Exhibit 10-4: Distribution Function for All Portfolios


Exhibit 10-5: Distribution Function for All Portfolios at > 95% Probability


AEP-EastOverlayed Cumulative Distribution Functions

All Plans

0.95

0.96

0.97

0.98

0.99

1.00

115,000 135,000 155,000 175,000 195,000 215,000

Millions of Dollars in Present Value

Cum Prob

Base Case (11) Accel Coal Ret (62) Alt Resc (80)

Green (83) No CCS (74) No CO2 (1)

AEP-EastOverlayed Cumulative Distribution Functions

All Plans

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

105,000 125,000 145,000 165,000 185,000 205,000 225,000

Millions of Dollars in Present Value

Cum Prob

Base Case (11) Accel Coal Ret (62) Alt Resc (80)

Green (83) No CCS (74) No CO2 (1)



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10.4 Conclusion from Risk Modeling

The Base Plan had the lowest cost at the 50% probability level but had the second highest cost at the 95% probability level (the Green Plan had the lowest). While the Green Plan has a lower RRaR at 95% probability, it is significantly more expensive at the 50% probability level. The risk mitigation benefits of the Green Plan are tied to potential extremes in CO2 pricing, as indicated from the discrete modeling results from Strategist where the Green Plan is the preferred plan under the Altruism pricing, but not under other pricing scenarios.

The results indicate that AEP-East should continue to aggressively pursue addition of renewables and DR/EE where regulatory support is provided, and to remain open to the possibility of the addition of nuclear capacity. Recent experience has shown that state regulatory bodies are under pressure from ratepayers to keep rates low, especially during the current economic climate, and as a result they may be reluctant to support efforts to increase energy diversity that are not required by a state or federal mandate if those initiatives cause near-term rates to increase. This may limit the levels of renewables and DR/EE that could potentially be employed in the resource mix. The levels used in the Hybrid Plan, while somewhat aggressive, are believed to be realistically achievable.

The Hybrid Plan, developed using a more recent, lower load forecast, does not show the need for baseload capacity even after all proposed coal unit retirements occur, which would suggest that, at this point in time consideration of a nuclear addition is not warranted. The URSA results show that the planned additions of CCS equipment on existing facilities, which is a component of the Hybrid Plan, produces a lower cost plan than excluding CCS. The addition of a full scale CCS equipment retrofit will be dependent first on the successful outcome of the Mountaineer pilot project and then on the federal incentives which are expected to be necessary to keep such retrofits at a reasonable cost to customers.



98



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11.0 Findings and Recommendations

11.1 Development of the “Hybrid” Plan

Using the intelligence gained from the Strategist runs for various pricing and sensitivity scenarios, an AEP-East “Hybrid” plan was created that primarily focused on the following:

While the IRP process was taking place, the Economic Forecasting group prepared a revised load forecast in April, 2010. The revised forecast reflected a downturn in economic conditions over AEP’s East service area and in turn, a reduction in AEP East’s peak and energy requirements compared to the forecast used in the IRP process. The “April” forecast showed a reduction in energy requirements of 4% - 8% and a 5% - 10% reduction in peak demand over the planning period compared to the load forecast used in the IRP process. In recognition of the April forecast’s lower peak loads, the Hybrid Plan deferred the amount of capacity that had been added in the various IRP optimization runs.

During the course of the 2010 IRP analysis, it became apparent that reducing the size of AEP’s significant carbon footprint would be necessary over the long-term due to the emerging likelihood of some level of CO2 emission limits in the future. Based on the analysis performed within the No CCS Retrofit view, CCS retrofits were introduced into the AEP-East plan so as to accelerate this further migration to a reduced CO2 position.

Due to the retirement of certain units that provide black start capability, the addition of quick-start CT capacity was accelerated to replace this function in certain operating areas.

Based on the array of discrete results from varying pricing scenarios and strategic portfolios, and the risk analysis described in Section 10, the Reference Case Optimal Portfolio was determined to be a reasonable basis for the development of the final AEP-East Hybrid Plan shown in Exhibit 11-1.

As stated above, during the development of the Hybrid Plan the timing and number of units added in the Reference Case Optimal Plan was adjusted to reflect the reduction in peak loads found in the April 2010 revised load forecast. In addition, the CCS retrofits assumed in the majority of the optimization runs were included in the Hybrid Plan. The reduction in peaking requirements with the April load forecast allowed the number of peaking resources to be reduced from 28 in the Reference Case to 16 in the Hybrid Plan, however an intermediate resource was added in place of eight of these CT’s to diversify the energy mix.

The Hybrid Plan identifies thermal capacity additions by duty cycle. With the exception of committed capacity additions, such as Dresden, or enhancements to existing resources, such as the Cook uprate, the thermal capacity identified is intended to represent “blocks” of capacity that fit that duty cycle and do not imply a specific solution or configuration.

The selection of the Hybrid Plan reflects management’s commitment to a diverse portfolio including renewable energy alternatives and demand reduction/energy efficiency. This resource portfolio compares favorably to other portfolios when subjected to robust statistical analysis, providing low reasonable life-cycle cost on average, and relatively low risk to its customers. Other benefits include:



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Keeping coal as a viable fuel in a carbon-constrained world through the use of CCS technology. AEP service territory encompasses some of the most prolific coal producing regions in the nation. AEP’s steeped history and core competency surrounding coal-based generation would also naturally support such a commitment.

With mandatory Renewable Portfolio Standards in force in Michigan, West Virginia, and Ohio, and a voluntary standard in Virginia, securing wind power ensures that AEP will be well positioned to achieve those standards.

Increased DR/EE, consistent with state objectives, assuming customer acceptance and full and contemporaneous rate recovery, could offer an effective means to reduce demand, energy usage, and as a result, our carbon footprint.

Ability to meet emission caps set forth in the NSR case Stipulated Agreement.

Exhibits 11-1 through 11-3 offer a summary of the Hybrid plan and the resulting AEP-East generating fleet from capacity and energy mix standpoint. From an environmental stewardship perspective, note that Exhibit 11-2 shows the respective AEP-East fleet continues to migrate to a lower carbon emitting portfolio. The most significant take-away, as shown in Exhibit 11-3, would be that, in 2020 and 2030, the plan relies more heavily on renewable resources and nuclear and less on baseload coal to meet its needs.



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102

Exhibit 11-2: AEP-East Generation Capacity


AE

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Cap

acit

y M

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AN

" P

ort

folio

0

5,00

0

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15,0

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20,0

00

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30,0

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00

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

MW of Capacity (Summer)

Coa

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103

Exhibit 11-3: Change in Energy Mix with Hybrid Plan Current vs. 2020 and 2030

Current AEP Generation Fleet Energy

Coal & OVEC84.05%

Nuclear12.87%

Wind1.336%

Gas (CC & CT & Diesel)0.72%

Coal W/CCS0.15%

Solar0.000%

Hydro (Pumped & ROR)

0.785%

Bio Mass0.09%

Coal & OVEC Coal W/CCS Nuclear Gas (CC & CT & Diesel)

Bio Mass Hydro (Pumped & ROR) Solar Wind

2020 AEP Generation Fleet Energy

Wind4.294%

Coal & OVEC61.41%

Solar0.171%


1.033%

Bio Mass1.56%

Coal W/CCS11.87%

Nuclear14.59%



Bio Mass Hydro (Pumped & ROR) Solar Wind

2030 AEP Generation Fleet Energy


Nuclear14.71%

Coal W/CCS14.77%

Bio Mass2.50%


1.045%

Solar0.497%

Coal & OVEC50.17%

Wind6.081%


Bio Mass Hydro (Pumped & ROR) Solar Wind Source: AEP Resource Planning



104

11.2 Comparison to 2009 IRP:

The 2009 IRP for AEP-East recommended a slightly different build profile than the current 2010 IRP. The most notable difference between the two plans is that the fleet capacity reductions associated with retiring older coal fired units now concludes in 2019 versus 2023 in the 2009 Plan. Also, Muskingum River 5 is expected to retire in 2015 rather than be retrofitted with an FGD system. This increases the fossil capacity to be removed from service during the next decade. Total new thermal capacity remains unchanged, although the 2009 Plan included a 628 MW peaking facility in 2018 which has been replaced in the 2010 Plan with two 314 MW peaking facilities, one in 2017 and one in 2018. These facilities are required primarily for system restoration, not peaking capacity. Renewable generation sources are generally consistent with the 2009 Plan, however new DSM has increased. This 2010 Plan also introduces Volt/Var Control technology to reduce consumption. A summary of the plan differences is presented in Exhibit 11-4.

Exhibit 11-4: Comparison of 2010 IRP to 2009 IRP

All Units in MW

DSM

Unit Retirements (summer-rating)

Environmental Retrofits

New

Demand Reduction (Cumul. Contribution)

Solar (Nameplate)

Wind (Nameplate)

Biomass (Derate

/New Facility

IVVC

2009 Plan (3,470) (113) 1,073 118 2,451 103 0

2010 Plan (5,943) (390) 1,468 225 2,152 150 100

Difference (2,473) (277) 395 107 (299) 47 100

Planned Resource Additions

2010 Vs 2009 IRP for AEP-East (10 Year Plan Period)

0

Peaking/ Intermediate/ Baseload

1,585

1,585

RENEWABLE

Planned Resource Reductions THERMAL




105

12.0 AEP-East Plan Implementation & Conclusions

Once the recommended overall AEP-East resource plan was selected, it was next evaluated from the perspective of its implementation across the region’s five member companies. This process involved consideration of:

Specific operating company resource assignment/allocations based on relative capacity positions; and

Attendant capacity settlement (“Pool”) effects.

12.1 AEP-East—Overview of Potential Resource Assignment by Operating Company

As described throughout this report, the recommended resource plan for AEP’s Eastern (PJM) zone was formulated on a region-wide view, recognizing that AEP plans and operates its eastern fleet on an integrated basis, as outlined in the AEP Interconnection (“Pool”) Agreement. As specified in the Pool Agreement, each Member Company (APCo, CSP, I&M, KPCo & OPCo) is required to provide an equitable contribution to the incremental capacity resource requirements of AEP-East. This contribution has been historically based on its relative percentage surplus/deficit reserve margin of each company.

Exhibit 12-1 identifies the resulting Member Company Reserve Margins over the next 20 years. As reflected in the chart, the result of this ownership regiment serves to:

Reduce the absolute capacity deficiency for each Member Company

Cause the reserve margins of all Member Companies to begin to converge over the 10-year IRP period.

Also, Appendix J identifies the Member Company timing and type of new capacity–CT, D (Dresden) CC, Biomass, Wind, – represented in the recommended (“Hybrid”) AEP-East capacity resource plan.



106

Resource Planning

Exhibit 12-1: Projected AEP-East Reserve Margin, By Company and System for IRP Period


AE

P-E

ast

(Po

ol)

Me

mb

er

Co

mp

any

Res

erve

Mar

gin

s20

10

IRP

(30

)

(20

)

(10

)

010203040506070

2010

201

12

012

2013

201

42

015

2016

201

72

018

2019

202

02

021

2022

202

320

24

2025

202

620

27

20

282

029

203

0

Reserve Margin (%)

AP

Co

(W

inte

r)C

SP

(S

umm

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I&M

(S

umm

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KP

Co

(Win

ter)

OP

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(S

umm

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AE

P E

ast

(Su

mm

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n:M

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ins

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re p

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ially

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set

by u

nit

retir

emen

ts.



107

12.2 AEP-East “Pool” Impacts

Under the AEP Pool Agreement, capacity cost sharing is determined by each Member Company assuming its Member Primary Capacity Reservation share of the overall (AEP-East zone) System Primary Capacity (calculated by multiplying each Member Company’s respective Member Load Ratio {MLR} by the total System Primary Capacity). Consequently, as new capacity is added or removed, all Member Companies’ Capacity Settlement payments or receipts are changed.

Exhibit 12-2 summarizes the projected incremental System Pool/Capacity Settlement impacts to the AEP-East zone Member Companies assumed in this recommended 2010 plan. While the largest portion of the incremental capacity resource ownership obligation for new capacity would be borne by APCo, the incremental annual capacity pool “credits” APCo would be, cumulatively, $449 million by the end of 2020

Exhibit 12-2: Incremental Capacity Settlement Impacts of the IRP

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020APCo - 65 6 92 78 72 (6) 7 (11) 74 73 CSP - (14) (30) (29) (32) 10 58 62 104 177 208 I&M - (21) (25) (33) (17) 51 21 44 69 21 22

KPCo - 3 5 4 9 22 34 37 77 39 42 OPCo - (33) 45 (34) (38) (155) (107) (151) (239) (310) (345) Total - 0 0 0 0 0 0 0 0 0 0

Capacity Settlement Benefits/(Costs) ($in Millions) - IRP Change

Source: AEP Financial Forecasting

12.3 New Capacity Lead Times

While the resource plan described in this report covers an extended time period, the only implementation commitments for which a firm consensus must be drawn at this time are those affecting resources that are timed to enter service roughly “one lead-time” into the future. New generation lead time naturally varies depending upon the resource type being contemplated. Depending on siting, land acquisition, permitting, design, engineering, and construction timetables–and whether certain elements (e.g., land or permitting) are already in-place–such lead-times may vary as shown in Exhibit 12-3:

Exhibit 12-3: New Capacity Lead Times

Technology Construction

Simple Cycle 1 1.5Combined Cycle 1.5 to 2 2Solid Fuels 2 to 4 4Nuclear 4 5Solar PV (e.g., 10 MW Juwi solar) 0.5 to 1 1Wind Farm 1 to 2 1Biomass Co-fire 0.5 to 1 0.5

Permitting, license, design Approximate Lead Time (years)




108

12.4 AEP-East Implementation Status

1) Wind Contracts (by 12/31/2010): Contracts have been signed for wind purchases for a total of 726 MW (nameplate) on behalf of APCo (376 MW), CSP (50 MW), I&M (150 MW), KPCo (100 MW), and OPCo (50 MW). Regulatory approvals have been received for some of these contracts in four of the five states (Virginia, West Virginia, Indiana, and Michigan), however two states, Virginia and Kentucky, denied inclusion of wind PPA costs. Virginia denied three contracts totaling 201 MW (Grand Ridge II, Grand Ridge III, and Beech Ridge), while Kentucky denied the 100 MW FPL Energy wind contract (Lee- Dekalb). No approval was sought or received in Ohio.

2) DSM Jurisdictional Activity:

Indiana:

Included in the Phase II Order of Cause 42693 are rules dictating the process for the development and implementation of energy efficiency programs. I&M has several “core-plus” and “core” programs that have Commission approval are expected to be implemented in 2010. During 2010, “core” programs will be transitioned to the State-wide third-party administrator.

Michigan:

Energy Optimization (energy efficiency) and renewable standards are included as part of a comprehensive energy law enacted in 2008.

On Dec. 19, 2008, I&M filed with the MPSC intent to use the State Independent Energy Optimization Program Administrator to meet the requirements of the law.

Kentucky:

Reestablished industrial collaborative process to begin offering programs to serve this customer class.

Ohio:

Three-year program plans filed in 2009 (Case No. 09-1090-EL-POR) for compliance with S.B. 221.

West Virginia:

APCo filed for a three-year program for energy efficiency in June, 2010 and is awaiting a ruling from the Commission.

3) Dresden CC Unit (2013): The partially built, 540MW (summer) unit has been purchased. Completion of construction is scheduled prior to June 1, 2013.

4) NG Combustion Turbines (2017 and 2018): Given the uncertainty surrounding efforts (or ability given the current RPM protocol) to either: 1) purchase PJM market capacity in the future; or 2) identify opportunities and acquire additional distressed assets, steps will ultimately need to be undertaken internally to evaluate Greenfield or Brownfield-site construction of CT capacity in the East Zone.



109

The New Generation Development siting advisory group has performed evaluations to establish a short-list, from a list of 40 potential sites–most of which are located in Ohio, Virginia, or West Virginia–originally identified by the group in April 2006. Such siting studies are intended to screen, score and rank potential CT or CC sites based on a multitude of factors and will be updated in the future as necessary.

Generation Asset Purchase Opportunities: Although some years remain before concrete action would be needed to have a greenfield CT plant on by 2017, AEP continues to monitor the regional market for potential asset purchase opportunities.

5) Solar (2010-2012): AEP-Ohio has a PPA for 10 MW of solar capacity which began commercial operation in June, 2010. This will meet the solar benchmarks included in SB 221 through 2011. Solar benchmarks for 2010, 2011 and 2012 are 5 GWh, 15 GWh, and 29 GWh respectively, as shown in Exhibit 2-3.

To implement the recommendations included in this plan, significant capital expenditures will be required. As stated earlier, this plan, while making specific recommendations based on available data, is not a commitment to a specific course of action.

12.5 Plan Impacts on Capital Spending

This Plan includes new capacity resource additions, as described, as well as unit uprates and assumed environmental retrofits. Such generation additions require a significant investment of capital. Some of these projects are still conceptual in nature, others do not have site-specific information to perform detailed estimates; however, it is important to provide an order of magnitude cost estimate for the projects included in this plan. As some of the initiatives represented in this plan span both East and West AEP zones, Exhibit 12-4 includes estimates for such projects over the entire AEP System.



110

Exhibit 12-4: Incremental Capital Spending Impacts of the IRP


It is important to reiterate the capital spend level reflected on the Exhibit 12-4 is “incremental” in that it does not include “Base”/business-as-usual capital expenditure requirements of the generating facilities sector or transmission and distribution capital requirements. Achieving this additional level of expenditure will therefore be a significant challenge going-forward and would suggest the Plan itself will remain under constant evaluation and is subject to change as, particularly, new AEP’s system-wide and operating company-specific “Capital Allocation” processes continue to evolve. Also, while the spend level includes cost to install Carbon Capture equipment, these projects are included only under the assumption that any comprehensive GHG/CO2 bill requiring significant

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111

reductions in CO2 emissions will include a provision to receive credits or allowances that would largely offset the cost of such equipment.

12.6 Plan Impact on CO2 Emissions (“Prism” Analysis)

The Hybrid Plan includes resource additions that will result in lowering AEP’s carbon emissions over the next 20 years. By retiring older, less efficient coal fired units, increasing nuclear capacity at the Cook plant, adding wind and solar resources, adding carbon capture and storage to larger coal units, and implementing energy efficiency programs, AEP has laid out a plan that is consistent with pending legislation and corporate sustainability.

To gauge those respective CO2 mitigation impacts incorporated into this resource planning, an assessment was performed that emulates an approach undertaken by the Electric Power Research Institute (EPRI). This profiling seeks to measure the contributions of various “portfolio” components that could, when taken together, effectively achieve such carbon mitigation through:

Energy Efficiency Renewable Generation Fossil Plant Efficiency, including coal-unit retirements Nuclear Generation Technology Solutions, including Carbon Capture and Storage

The following Exhibit 12-5 reflects those comparable components within this 2010 IRP as set forth as a multi-colored “prism” that are anticipated to contribute to the overall AEP-East system’s initiatives to reduce its carbon footprint:



112

Exhibit 12-5: AEP-East System CO2 Emission Reductions, by “Prism” Component

AEP - EAST CO2 PROFILE

55,000

65,000

75,000

85,000

95,000

105,000

115,000

125,000

135,000

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

YEAR

KT

ON

NE

S o

f C

O2

DR/EE

Renewables

Retirements & NSR SO2

Cook Uprates

CCS

Hybrid

Hybrid Plan Emissions

Business As Usual Emissions

44.8 M Tonne

(36.5%) Reduction


12.7 Conclusions

The recommended AEP-East capacity resource plan provides the lowest reasonable cost solution through a combination of traditional supply, renewable and demand-side resources. The most recent (April 2010) “tempered” load growth, combined with the completion of the Dresden natural gas-combined cycle facility, additional renewable resources, increased DR/EE initiatives, and the proposed capacity uprate of the Cook Nuclear facility allow AEP-East region to meet its reserve requirements until the 2018-2019 timeframe, at which point modeling indicates new peaking capacity will be required. Other than the aforementioned D.C. Cook uprate, no new baseload capacity is required over the 10-year Planning Period.

The Plan also positions the AEP-East Operating Companies to achieve legislative or regulatory mandated state renewable portfolio standards and energy efficiency requirements, and sets in place the framework to meet potential CO2 reduction targets and emerging U.S. EPA rulemaking around HAPs and CCR at the intended least reasonable cost to its customers.

The resource planning process is becoming increasingly complex given these uncertainties as well as spiraling technological advancements, changing economic and other energy supply fundamentals, uncertainty around demand and energy usage patterns as well as customer acceptance for embracing efficiency initiatives. All of these uncertainties necessitate flexibility in any on-going



113

plan. Moreover, the ability to invest in capital-intensive infrastructure is increasingly challenged in light of current economic conditions, and the impact on the AEP-East Operating Companies’ customer costs-of-service/rates will continue to be a primary planning consideration.

Other than those initiatives that fall within some necessary “actionable” period over the next 2-3 years, this long-term Plan is also not a commitment to a specific course of action, since the future, now more than ever before, is highly uncertain, particularly in light of the current economic conditions, the movement towards increasing use of renewable generation and end-use efficiency, as well as legislative and regulated proposals to control greenhouse gases and numerous other hazardous pollutants… all of which will likely result in either the retirement or costly retrofitting of all existing AEP-East coal units.

Finally, bear in mind that the planning process is a continuous activity; assumptions and plans are continually reviewed as new information becomes available and modified as appropriate. Indeed, the resource expansion plan reported here reflects, to a large extent, assumptions that are clearly subject to change. In summary, it represents a very reasonable “snapshot” of future requirements at this particular point in time.



114



115

APPENDICES



116

Appendix A, Figure 1 Existing Generation Capacity, AEP-East Zone

Plant Name Unit No.In-Service

DateAEP Own/ Contract

Winter Capability

(MW)

Summer Capability

(MW) Fuel Type

SCR Installation

Year

FGD Installation

YearSuper

Critical Age

Amos 1 1971 O 790 800 Coal 2005 2011 Y 39Amos 2 1972 O 790 790 Coal 2004 2010 Y 38Amos 3 1973 O 433 428 Coal 2004 2009 Y 37Clinch River 1 1958 O 235 230 Coal -- -- N 52Clinch River 2 1958 O 235 230 Coal -- -- N 52Clinch River 3 1961 O 235 230 Coal -- -- N 49Glen Lyn 5 1944 O 95 90 Coal -- -- N 66Glen Lyn 6 1957 O 240 235 Coal -- -- N 53Kanawha River 1 1953 O 200 200 Coal -- -- N 57Kanawha River 2 1953 O 200 200 Coal -- -- N 57Mountaineer 1 1980 O 1,314 1,299 Coal 2004 2007 Y 30Sporn 1 1950 O 150 145 Coal -- -- N 60Sporn 3 1951 O 150 145 Coal -- -- N 59APCo Coal 5,067 5,022 42

Ceredo 1-6 2001 (a) O 516 450 Gas (CT) -- -- N 9APCo Gas 516 450 9

APCo Hydro Various O 92 50 Hydro -- --Summersville 1-2 2001 C 28 14 Hydro -- -- 9APCo Hydro (b) 119 64 9

Smith Mountain 1 1965 O 66 66 PSH -- -- -- 45Smith Mountain 2 1965 O 174 174 PSH -- -- -- 45Smith Mountain 3 1980 O 105 105 PSH -- -- -- 30Smith Mountain 4 1966 O 174 174 PSH -- -- -- 44Smith Mountain 5 1966 O 66 66 PSH -- -- -- 44APCo Pumped Storage 585 585 42

APCo Wind Various (c) C 58 45 Wind -- -- --

Total APCo 6,346 6,166

Cardinal 2 1967 C 595 585 Coal 2004 2008 Y 43Cardinal 3 1977 C 630 630 Coal 2004 2012 Y 33Buckeye Coal 1,225 1,215 38

Robert Mone 1-3 2001 (d) C 134 44 Gas (CT) -- -- -- 9Buckeye Gas 134 44 9

Total Buckeye 1,359 1,259

Beckjord 6 1969 O 52 52 Coal -- -- N 41Conesville 3 1962 O 165 165 Coal -- -- N 48Conesville 4 1973 O 337 337 Coal 2009 2009 Y 37Conesville 5 1976 O 400 400 Coal 2015 1976 N 34Conesville 6 1978 O 400 400 Coal 2015 1978 N 32Picway 5 1955 O 100 95 Coal -- -- N 55Stuart 1 1971 O 151 151 Coal 2004 2008 Y 39Stuart 2 1970 O 151 151 Coal 2004 2008 Y 40Stuart 3 1972 O 151 151 Coal 2004 2008 Y 38Stuart 4 1974 O 151 151 Coal 2004 2008 Y 36Zimmer 1 1991 O 330 330 Coal 2004 1991 Y 19CSP Coal 2,388 2,383 35

Waterford 1-6 2002 (a) O 840 810 Gas (CC) 2002 -- N 8Darby 1-6 2002 (e) O 507 438 Gas (CT) 2002 -- N 8Lawrenceburg 1-6 2004 (e) O 1,186 1,120 Gas (CC) -- -- N 6Stuart Diesel 1-4 1969 O 3 3 Oil (Diesel) -- -- N 41CSP Gas/Oil 2,536 2,371 7

CSP Wind Various (c) C 7 7 Wind -- -- --

CSP Solar Various (f) C 1 2 Solar -- -- --

Total CSP 4,931 4,762(a) Acquired in 2005(b) Hydro capacity is rated at expected annual average output(c) The capacity of the Wind Energy Projects are listed at the preliminary PJM credit, 13% of the nameplate capacity(d) The listed Mone capacity is the net impact of the various contracts with Buckeye Power(e) Acquired in 2007 by AEP Generating Co, CSP receives capacity and energy via agreement(f) The capacity of the Solar Energy Projects are listed at the preliminary PJM credit, 6.67%(winter) and 38%(summer) of the nameplate capacity

AEP System - East Zone(Including Buckeye Power Capacity per Operating Agreement)

Existing Generation Capacity as of June 1, 2010

APCo

Cardinal-Buckeye

CSP



117

Appendix A, Figure 2 Existing Generating Capacity, AEP-East Zone (cont’d)

Plant Name Unit No.In-Service

DateAEP Own/ Contract

Winter Capability

(MW)

Summer Capability

(MW) Fuel Type

SCR Installation

Year

FGD Installation

YearSuper Critical Age

Rockport 1 1984 O 1,122 1,118 Coal 2017 2017 Y 26Rockport 2 1989 C 1,105 1,105 Coal 2019 2019 Y 21Tanners Creek 1 1951 O 145 145 Coal -- -- N 59Tanners Creek 2 1952 O 145 145 Coal -- -- N 58Tanners Creek 3 1954 O 205 195 Coal -- -- N 56Tanners Creek 4 1964 O 500 500 Coal -- -- Y 46I&M Coal 3,222 3,208 32

I&M Hydro (b) 15 11 Hydro -- -- --

Cook Nuclear 1 1975 O 994 972 Nuclear -- -- -- 35Cook Nuclear 2 1978 O 1,121 1,057 Nuclear -- -- -- 32I&M Nuclear 2,115 2,029 33

I&M Wind Various (c) C 22 22 Wind -- -- --

Total I&M 5,374 5,270

Big Sandy 1 1963 O 278 273 Coal -- -- N 47Big Sandy 2 1969 O 800 800 Coal 2004 2015 Y 41Rockport 1 1984 O 198 197 Coal 2017 2017 Y 26Rockport 2 1989 C 195 195 Coal 2019 2019 Y 21KPCo Coal 1,471 1,465 37

Total KPCo 1,471 1,465 37

Amos 3 1973 O 867 857 Coal 2004 2009 Y 37Cardinal 1 1967 O 595 585 Coal 2004 2008 Y 43Gavin 1 1974 O 1,320 1,315 Coal 2004 1994 Y 36Gavin 2 1975 O 1,320 1,315 Coal 2004 1994 Y 35Kammer 1 1958 O 210 200 Coal -- -- N 52Kammer 2 1958 O 210 200 Coal -- -- N 52Kammer 3 1959 O 210 200 Coal -- -- N 51Mitchell 1 1971 O 770 770 Coal 2007 2007 Y 39Mitchell 2 1971 O 790 790 Coal 2007 2007 Y 39Muskingum River 1 1953 O 205 190 Coal -- -- N 57Muskingum River 2 1954 O 205 190 Coal -- -- N 56Muskingum River 3 1957 O 215 205 Coal -- -- N 53Muskingum River 4 1958 O 215 205 Coal -- -- N 52Muskingum River 5 1968 O 600 600 Coal 2005 2015 Y 42Sporn 2 1950 O 150 145 Coal -- -- N 60Sporn 4 1952 O 150 145 Coal -- -- N 58Sporn 5 1960 O 0 0 Coal -- -- Y 50OPCo Coal 8,032 7,912 41

OPCo Hydro 1983 (b) O 26 20 Hydro -- -- -- 27

OPCo Wind Various (c) C 7 7 Wind -- -- --

OPCo Solar Various (e) C 1 2 Solar -- -- --

Total OPCo 8,064 7,941(b) Hydro capacity is rated at expected annual average output.(c) The capacity of the Wind Energy Projects are listed at the preliminary PJM credit, 13% of the nameplate capacity(f) The capacity of the Solar Energy Projects are listed at the preliminary PJM credit, 6.67%(winter) and 38%(summer) of the nameplate capacity

TOTAL AEP-East (excl. OVEC) 27,546 26,863 OVEC Purchase Entitlement 980 947TOTAL AEP-East 28,526 27,810

Totals by type Coal 22,385 22,152Nuclear 2,115 2,029Hydro 745 680

Gas/Diesel 3,186 2,865Wind 93.30 80.30Solar 1.36 3.84Total 28,526 27,810

AEP System - East Zone

I&M

OPCo

KPCo

(Including Buckeye Power Capacity per Operating Agreement)Existing Generation Capacity as of June 1, 2010



118

Appendix B, Figure 1 Assumed FGD Scrubber Efficiency and Timing

Current Scrubber xEfficiency - % New - FGD Installs FGD - Upgraded

Units 2010 Month / YearScrubber Efficiency - % Month / Year

Scrubber Efficiency - %

Amos 1 - Feb-11 95.0 Apr-11 96.0Amos 2 - Mar-10 96.0Amos 3 97.0 - - - -Big Sandy 2 - Jun-15 98.0 - -Cardinal 1 95.5 - - - -Cardinal 2 95.5 - - - -Cardinal 3 - Jan-12 95.0 Jan-13 96.5Conesville 4 94.5 - - Jan-11 97.0Conesville 5 96.0 - - - -Conesville 6 96.0 - - - -Gavin 1 94.5 - - - -Gavin 2 95.0 - - - -Mitchell 1 97.7 - - - -Mitchell 2 98.0 - - - -Mountaineer 1 98.5 - - Jan-18 98.0Rockport 1 - Jun-17 95.0 - -Rockport 2 - Jun-19 95.0 - -Stuart 1-4 97.0 - - - -Zimmer 1 93.0 - - - -

Notes: Assumed scrubber efficiencies per T. A. March (4/23/10), Amos 1 per WSR (4/23/10) Delayed FGD in-service per MSC10-3 maintenance schedule, thus delayed scrubber upgrade 1 month.



119

Appendix B, Figure 2 Assumed Capacity Changes Incorporated into Long Range Plan

AEP

East

ern

Flee

tAn

ticip

ated

Cap

acity

Cha

nges

Inco

rpor

ated

into

Lon

g-Ra

nge P

lanni

ngUn

it / A

mou

nt / T

imin

g

Capa

city

Ratin

g ND

C (M

W)

HP/1s

t RH

Turb

ine A

DSP

Impr

ovem

ent

(18 M

W)

In-S

ervic

e Da

te

HP/1s

t RH

Turb

ine A

DSP

Impr

ovem

ent 8

00-

serie

s (

12 M

W) In

-Ser

vice

Date

HP A

DSP

Turb

ine

Impr

ovem

ent

1300

serie

s

(20-

MW)

In-S

ervic

e Da

te

Main

Sto

pValv

e -MS

V/CV

Ch

ange

out

(35

-MW

)

In-S

ervic

e Da

te

Carb

on C

aptu

re

Proj

ect (

Com

m.

Oper

.)In

-Ser

vice

Date

FGD

Dera

te

(MW

)Ne

t (MW

) afte

r FG

DIn

-Ser

vice

Date

Amos

180

081

2Fe

b-11

(22)

790

Feb-

11

Big

Sand

y 126

027

8Ja

n-10

Big

Sand

y 280

0

(4

0)76

0Ju

n-15

Card

inal

159

5

Card

inal

259

5

Card

inal

363

0

(1

0)62

0Ja

n-12

Gavin

113

20

0

Jun-

09

11

25Ja

n-20

Gavin

213

20

0

Jun-

11

Mou

ntain

eer 1

1314

1256

Nov-

15

Mou

ntain

eer 1

1256

1125

Jan-

19

Rock

port

113

20

13

55Ju

n-17

(35)

1320

Jun-

17

Rock

port

213

00

13

35Ju

n-19

(35)

1300

Jun-

19

Sour

ces:

1)

Incr

ease

in ca

pacit

y sho

wn at

Big

San

dy 1

(18-

MW),

Card

inal

1+2 c

apac

ity in

crea

se fr

om 58

0-M

W to

595-

MW w

ith a

sum

mer

der

ate i

n Ma

y-Oct

per

N. A

kins (

2/15/1

0).

2) T

he 20

-MW

capa

city i

ncre

ase a

t bot

h Ga

vin 1+

2 hav

e bee

n re

mov

ed in

June

of 2

009 &

2011

, how

ever

ther

e is a

hea

t rat

e im

prov

emen

t per

D. L

. Unt

ch/D

. M. C

ollin

s (5/2

7/09)

.

To b

e con

siste

nt w

ith th

e AEP

-Eas

t Cap

acity

upd

ate p

er N

. Akin

s (2/1

5/10)

, the

fore

cast

will

show

a 5-

MW

der

ate i

n Ju

ly &

Augu

st.

3) R

evise

d m

ain st

op va

lve (M

SV) r

atin

gs o

f 35-

MW p

er M

. A. G

ray (

8/30/0

6).

4) M

ount

ainee

er 1

inclu

des a

a se

ason

al de

rate

in th

e per

iods

Jun-

Sep

per R

. E. D

ool (

2/04/1

0).

5) C

arbo

n Ca

ptur

e pro

ject w

hich

beg

an in

Oct

ober

2009

will

refle

ct a

6-MW

capa

city r

educ

tion.

The

2010

Stra

tegi

c Plan

CLR

(2/09

/10) a

ssum

es th

e com

mer

cial

op

erat

ion

of ca

rbon

capt

ure a

t Mou

ntain

eer;

capa

city r

educ

tion

of an

addi

tiona

l (58

-MW

) 11/2

015 a

nd (1

31-M

W) 1

/2019

for a

tota

l of 1

95-M

W.

6) F

orec

ast s

hows

a ca

pacit

y red

uctio

n fo

r CCS

of 1

95-M

W at

Gav

in 1

effe

ctive

1/20

20 p

er th

e 201

0 Stra

tegi

c Plan

. 7)

No

chan

ge in

uni

t cap

acity

afte

r the

MSV

/FGD

are i

nsta

lled

at R

ockp

ort 1

+2 p

er D

. L. U

ntch

/D. M

. Col

lins (

1/14/1

0).

8) T

he F

GD at

Am

os 1

has b

een

delay

ed fr

om 1/

1/201

1 to

2/1/20

11, a

nd th

e FGD

at M

uskin

gum

5 ha

s bee

n ca

ncell

ed



120

Appendix C, Key Supply Side Resource Assumptions

AEP SYSTEM-EAST ZONE New Generation Technologies

Key Supply-Side Resource Option Assumptions (a)(b)(c)

Trans. Emission Rates Capacity OverallCapability (MW) Cost (e) SO2 (g) NOX CO2 Factor Availability

Type Std. ISO ($/kW) (Lb/mmBtu) (Lb/mmBtu) (Lb/mmBtu) (%) (%)

Base LoadPulv. Coal (Ultra-Supercritical) (h) 618 24 0.07 0.070 205.3 85 89.6CFB (h) 585 26 0.07 0.070 210.3 80 90.7IGCC ("F"Class)(h) 630 24 0.01 0.057 205.3 85 87.5IGCC ("H"Class)(h) 862 17 0.01 0.057 205.3 85 87.5Nuclear (US ABWR) 1,606 64 0.00 0.000 0.0 90 94.0

Base Load (90% CO2 Capture New Unit)Pulv. Coal (Ultra-Supercritical) (h) 526 29 0.0708 0.070 20.5 85 89.6CFB (w/ CCS, Amine, NOAK)(h) 497 30 0.0665 0.070 20.5 80 89.6IGCC ("F"Class, w/ CCS, NOAK)(h) 535 28 0.0090 0.057 20.5 85 87.5IGCC ("F"Class w/ 20% Biomass, w/ CCS)(h) 482 31 0.0090 0.057 11.4 85 87.5IGCC ("H"Class, w/ CCS)(h) 776 19 0.0090 0.057 20.5 85 87.5

IntermediateCombined Cycle (1X1 GE7FA) 255 60 0.0007 0.008 116.0 25 89.1Combined Cycle (2X1 GE7FA, w/ Duct Firing) 621 60 0.0007 0.008 116.0 60 89.1Combined Cycle (1X1 GE7FH) 385 60 0.0007 0.008 116.0 25 89.1Combined Cycle (1X1 SW501G) 387 60 0.0007 0.008 116.0 25 89.1Combined Cycle (2X1 GE7FB, w/ Duct Firing) 652 60 0.0007 0.008 116.0 60 89.1Combined Cycle (2X1 M701G) 962 60 0.0007 0.008 116.0 60 89.1

Intermediate (90% CO2 Capture New Unit)Combined Cycle (2X1 GE7FB, w/ Amine Scrubbing) 554 71 0.0007 0.008 11.6 60 89.1Combined Cycle (2X1 M701G, w/ Chilled Ammonia) 818 71 0.0007 0.008 11.6 60 89.1

PeakingCombustion Turbine (2X1GE7EA) 164 57 0.0007 0.009 116.0 3 90.1Combustion Turbine (2X1GE7EA,w/ Inlet Chillers) 164 59 0.0007 0.009 116.0 3 90.1Combustion Turbine (2X1GE7FA) 332 57 0.0007 0.009 116.0 3 90.1Combustion Turbine (2X1GE7FA, w/ Inlet Chillers) 332 59 0.0007 0.009 116.0 3 90.1Aero-Derivative (1X GE LM6000PF) 46 60 0.0007 0.056 116.0 3 89.1Aero-Derivative (1X GE LM6000PC) 60 60 0.0007 0.056 116.0 90 89.1Aero-Derivative (1X GE LMS100PB, w/ Inlet Chillers) 98 59 0.0007 0.009 116.0 30 90.1Aero-Derivative (2X GE LMS100PB, w/ Inlet Chillers) 196 59 0.0007 0.009 116.0 3 90.1CAES Facility 300 60 0.0007 0.008 116.0 47 95.0

Notes: (a) Installed cost, capability and heat rate numbers have been rounded.

(b) All costs in 2010 dollars. Assume 2.0% escalation rate for 2010 and beyond.

(c) $/kW costs are based on Standard ISO capability.

(d) Total Plant & Interconnection Cost w/AFUDC (AEP-East rate of 4.90%,site rating $/kW).

(e) Transmission Cost ($/kW,w/AFUDC).

(f) Levelized Fuel Cost (40-Yr. Period 2011-2050)

(g) Based on 4.5 lb. Coal.

(h) Pittsburgh #8 Coal.



121

Appendix D, AEP-East Summer Peak Demands, Capabilities and Margins

Pla

nned

Cap

acity

Ad

ditio

nsU

nits

MW

(i)

200

7/0

8(k

)21

,087

(1)

21,

087

439

0.9

571

.079

22,

301

1,39

123

,692

28,

76

92

,574

26,

195

7.6

1%2

4,2

02

510

510

200

8/0

9(k

)21

,326

(1)

21,

326

439

0.9

581

.080

22,

570

1,40

023

,970

28,

83

01

,793

27,

037

7.6

5%2

4,9

69

999

999

200

9/1

0(k

)21

,642

(59

)(1

)2

1,64

147

30

.957

1.0

802

2,87

31,

400

24,2

732

8,8

07

1,1

312

7,67

68

.41%

25,

34

81,

075

1,0

7520

10

/11

(k)

20,3

95(1

6)

(1)

20,

394

445

0.9

551

.083

21,

631

1,40

523

,036

28,

41

71

,207

10 M

W S

olar

& 2

50 M

W W

ind

360

27,

246

10.

90%

24,

27

61,

208

1,2

4020

11

/12

(k)

20,6

74(2

06)

(59

)2

0,61

544

50

.955

1.0

832

1,87

11,

396

23,2

672

8,4

12

1,4

9210

MW

Sol

ar &

100

MW

Win

d17

02

6,97

38

.95%

24,

55

91,

244

1,2

9220

12

/13

(k)

21,3

75(3

99)

(16

)2

1,36

044

50

.950

1.0

802

2,60

51,

396

24,0

012

7,8

83

873

10 M

W S

olar

& 1

00 M

W W

ind

170

27,

080

7.2

6%2

5,1

14

1,04

81

,113

201

3/1

4(k

)21

,741

(65

1)(2

06)

21,

536

445

0.9

571

.080

22,

806

1,39

624

,202

27,

87

5(4

)54

0 M

W D

CC

2 &

10

MW

Sol

ar &

10

0 M

W

Win

d5

570

28,

506

7.9

5%2

6,2

40

1,46

12

,038

201

4/1

520

,755

(93

2)(3

99)

20,

356

445

0.9

571

.080

21,

532

1,39

622

,928

27,

25

6(4

)26

MW

Sol

ar &

300

MW

Win

d49

02

7,93

68

.19%

25,

64

82,

099

2,7

2020

15

/16

20,8

69(1

,15

3)

(65

1)2

0,21

844

50

.957

1.0

802

1,38

21,

396

22,7

782

6,4

01

(4)

26 M

W S

olar

& 4

00 M

W W

ind

620

27,

143

8.0

2%2

4,9

66

1,50

92

,188

201

6/1

720

,967

(1,2

37

)(9

32)

20,

035

445

0.9

571

.080

21,

184

1,39

622

,580

25,

29

4(4

)26

MW

Sol

ar &

250

MW

Win

d42

02

6,07

96

.00%

24,

51

41,

200

1,9

34

201

7/1

821

,093

(1,3

12

)(1

,15

3)

19,

940

445

0.9

571

.080

21,

082

1,39

622

,478

24,

69

7(4

)31

4 M

W C

T*

& 2

6 M

W S

olar

& 1

50 M

W

Win

d3

430

25,

825

5.3

4%2

4,4

46

904

1,9

68

201

8/1

921

,224

(1,3

77

)(1

,23

7)

19,

987

445

0.9

571

.080

21,

133

1,39

622

,529

24,

23

4(4

)31

4 M

W C

T*

& 2

6 M

W S

olar

& 5

0 M

W

Win

d3

300

25,

693

5.0

9%2

4,3

85

475

1,8

56

201

9/2

021

,351

(1,4

65

)(1

,31

2)

20,

039

445

0.9

571

.080

21,

189

1,39

622

,585

22,

65

8(4

)26

MW

Sol

ar &

100

MW

Win

d23

02

4,14

05

.02%

22,

92

8(1

,06

1)

343

202

0/2

121

,391

(1,5

69

)(1

,37

7)

20,

013

445

0.9

571

.080

21,

161

1,39

622

,557

22,

65

8(4

)26

MW

Sol

ar

& 1

50 M

W W

ind

290

24,

169

5.0

2%2

2,9

56

(1,0

33

)39

9

No

tes:

(a)

Ba

sed

on

(Ap

ril 2

010

) L

oad

Fo

reca

st (

with

impl

ied

PJM

div

ers

ity f

acto

r)(g

)co

ntin

ued

(h)

Incl

udes

:In

clu

des

Mon

ong

ahe

la P

ow

er

& N

CE

MC

CC

S D

ER

AT

ES

:C

P&

L R

ockp

ort

sal

e th

rou

gh 2

009

/10

20

09/1

0: M

oun

tain

eer

1: 6

MW

Ea

st-W

est

tra

nsfe

r o

f 2

50 M

W in

200

7/08

(b)

Exi

stin

g pl

us

app

rove

d D

R, E

E,

and

IVV

20

15/1

6: M

oun

tain

eer

1: 5

8 M

WS

ale

of

50

MW

to

Wis

cons

in P

ublic

Ser

vice

in 2

007

/08

20

18/1

9: M

oun

tain

eer

1: 1

31

MW

Sa

le o

f 1

00 M

W t

o W

olv

erin

e in

20

07/

08

- 2

009/

10, n

ette

d(c

)T

he

impa

ct o

f n

ew

DS

M is

de

laye

d tw

o y

ears

to r

epr

ese

nt e

ithe

r2

019

/20:

Ga

vin

1: 1

95 M

Wa

gain

st a

10

0 M

W p

urc

has

e f

rom

Dyn

egy

in 2

007/

08(1

) its

impa

ct o

n a

ctu

al lo

ad

fee

din

g th

rou

gh t

he P

JM lo

ad f

ore

cast

pro

cess

or

20

21/2

2: A

mo

s 3

: 19

5 M

WC

onst

ella

tion

pu

rch

ase

of

315

MW

in 2

009

/10-

201

1/12

(2)

verif

ica

tion

prio

r to

be

ing

offe

red

into

th

e P

JM R

PM

au

ctio

n.F

GD

DE

RA

TE

S:

Pu

rcha

se to

co

ver

CS

P's

for

me

r M

ono

nga

hela

Po

we

r lo

ad

20

07/0

8: C

ard

ina

l 1&

2:

20 M

W e

ach

; S

tua

rt 1

-4:

1 M

W e

ach

in 2

007/

08 -

20

09/1

0(d

)D

ema

nd R

esp

onse

ap

pro

ved

by

PJM

in t

he p

rior

pla

nni

ng

yea

r2

008

/09:

Am

os

3: 3

5 M

WD

arb

y a

nd

La

wre

nce

burg

are

sol

d in

th

e 2

007

/08

RP

M a

uct

ion

20

09/1

0: A

mo

s 2

: 22

MW

; Co

nes

ville

4:

2 M

W(b

y A

EP

an

d P

SE

G)

(e)

Inst

alle

d R

eser

ve M

argi

n (I

RM

) =

15

.0%

thr

oug

h 2

009/

10, 1

5.5

% th

roug

h 2

01

1/2

012

, the

n 16

.2%

20

10/1

1: A

mo

s 1

: 22

MW

; Kyg

er

Cre

ek 4

-5: 3

MW

eac

hM

ISO

Sal

e o

f 3

48 M

W in

20

08/

09

an

d 2

5 M

W in

200

9/1

0F

ore

cast

Poo

l Re

quire

men

t (F

PR

) =

(1

+ I

RM

) *

(1 -

PJM

EF

OR

d)2

011

/12:

Car

din

al 3

: 10

MW

; Kyg

er

Cre

ek 1

-3: 3

MW

eac

hS

ale

of

22

MW

fro

m T

ann

ers

Ck.

4 in

20

10/1

1-2

011

/12

and

30

MW

in 2

012

/13

20

12/1

3: C

lifty

Cre

ek 4

,6:

2 M

W e

ach

Cer

edo

/Da

rby/

Gle

n L

yn S

ale

to

AM

PO

,AT

SI,

and

IME

A

(f)

Incl

ud

es:

20

13/1

4: C

lifty

Cre

ek 1

-3,5

: 2 M

W e

ach

20

10/1

1-2

012/

13 (

45

MW

, 37

4 M

W, 1

57 M

W)

FR

R v

iew

of

oblig

atio

ns

onl

y.2

015

/16:

Big

San

dy

2:

40 M

WR

PM

Au

ctio

n S

ale

s 20

07/0

8 -

201

2/1

3 (

777

MW

, 140

6 M

W, 1

389

MW

Buc

keye

Ca

rdin

al a

nd M

on

e o

blig

atio

ns2

017

/18:

Roc

kpor

t 1:

35

MW

, 1

463

MW

, 1

404

MW

, 6

90 M

W IC

AP

)2

019

/20:

Roc

kpor

t 2:

35

MW

3.6

MW

ca

pac

it y c

red

it fr

om

SE

PA

's P

hilp

ot D

am

via

Blu

e R

idge

con

tra

ct(g

)R

efle

cts

the

follo

win

g su

mm

er

capa

bilit

y a

ssu

mpt

ion

s:

SC

R D

ER

AT

ES

:A

EP

sh

are

of

OV

EC

cap

acity

20

09/1

0: C

one

svill

e 4

: 0 M

W(i)

New

win

d a

nd

so

lar

cap

acity

va

lue

is a

ssu

med

to

be

13

% a

nd

38%

of

nam

epla

teA

ssu

mes

hyd

ro u

nits

, in

clu

din

g S

um

mer

svill

e, a

re d

era

ted

to A

ugu

st a

vera

ge o

utp

ut in

20

14/1

52

019

/20:

Con

esv

ille

5-6

: 4

MW

ea

chW

IND

FA

RM

(n

ame

pla

te):

20

20/2

1: R

ockp

ort

1: 0

MW

(j)B

egi

nn

ing

200

8/0

9,

base

d o

n 1

2-m

onth

avg

. AE

P E

FO

Rd

in e

Ca

paci

ty2

75 M

W T

ota

l2

022

/23:

Roc

kpor

t 2:

0 M

Was

of

twe

lve

mo

nth

s en

ded

9/30

/07

EF

FIC

IEN

CY

IMP

RO

VE

ME

NT

S:

RE

TIR

EM

EN

TS

:2

007

/08

: C

ard

ina

l 2: 0

MW

(tu

rbin

e)

(off

set

to F

GD

der

ate

)2

010

/11:

Sp

orn

5(k

)A

ctua

l PJM

fo

reca

st2

008

/09

: R

ockp

ort

1:

20 M

W (

turb

ine)

; A

mo

s 3

: 35

MW

(va

lve)

20

12/1

3: C

one

svill

e 3

; Mu

skin

gum

Riv

er

2,4

200

9/1

0:

Am

os

2: 1

2 M

W (

turb

ine)

; B

ig S

andy

1: 0

MW

(tu

rbin

e);

Gav

in 1

: 0

MW

(tu

rbin

e)2

014

/15:

Mus

king

um

Riv

er 1

,3

(*)

Com

bus

tion

Tu

rbin

es (

CT

) a

dded

to m

ain

tain

Bla

ck S

tart

cap

abili

ty2

010

/11

: A

mo

s 1

: 12

MW

(tu

rbin

e)2

015

/16:

Gle

n Ly

n 5-

6; M

usk

ingu

m R

ive

r 5

201

1/1

2:

Coo

k 2

: 14

MW

(U

pra

te);

Ga

vin

2: 0

MW

(tu

rbin

e)2

016

/17:

Tan

ners

Ck.

1-3

; C

linch

R. 1

-32

014

/15

: C

ook

2:

45 M

W (

Up

rate

)2

017

/18:

Pic

way

5; S

por

n 1

-42

015

/16

: C

ook

1:

100

MW

(U

pra

te);

Co

ok 2

: 68

MW

(U

pra

te)

20

18/1

9: K

ana

wh

a R

ive

r 1

&2

201

6/1

7:

Coo

k 1

: 68

MW

(U

pra

te)

20

19/2

0: K

am

mer

1-3

; B

ig S

and

y 1;

Tan

ners

Ck.

42

017

/18

: C

ook

2:

68 M

W (

Up

rate

); R

ockp

ort

1:

35 M

W (

valv

e) (

off

set t

o F

GD

de

rate

)2

018

/19

: C

ook

1:

68 M

W (

Up

rate

)2

019

/20

: R

ockp

ort

2:

35 M

W (

valv

e) (

off

set t

o F

GD

de

rate

)

AE

P

EF

OR

d (j)

Ava

ilab

le

UC

AP

Ne

t Pos

ition

w

/o N

ew

Ca

paci

ty

Re

sou

rces

AE

P P

os

itio

n (

MW

)A

nnu

al

Pu

rch

ases

Ne

t IC

AP

Pla

nnin

g Y

ear

Ne

t In

tern

al

Dem

and

Inte

rna

l D

em

and

(a)

Tot

al

UC

AP

O

blig

atio

n

DS

M (

b)

UC

AP

O

blig

atio

nN

et U

CA

P

Mar

ket

Ob

liga

tion

(f)

Exi

stin

g C

apa

city

&

Pla

nne

d C

ha

nge

s (g

)

Ob

ligat

ion

to

PJM

Net

Po

sitio

n

w/

Ne

w

Cap

aci

ty

Ne

t C

apac

ity

Sal

es

(h)

Pro

ject

ed

DS

M

Imp

act

(c)

Inte

rru

ptib

le

Dem

and

R

espo

nse

(d)

Dem

and

R

espo

nse

F

acto

r

Fo

reca

st

Po

ol R

eq't

(e)

AE

P S

YS

TE

M -

EA

ST

ER

N Z

ON

EP

roje

cte

d S

um

me

r P

eak

Dem

and

s, G

en

era

tin

g C

ap

ab

ilit

ies,

an

d M

arg

ins

(U

CA

P)

Ba

sed

on

(A

pri

l 20

10

) L

oa

d F

ore

cas

t2

010

IR

P (

Hyb

rid

Pri

me

)



122

Appendix E, Plan to Meet 10% of Renewable Energy Target by 2020

2009

075

00.

8%0

00

0.0%

00

00.

0%0

00

0.0%

00

00.

0%0

00

0.0%

075

00.

2%20

100

276

02.

7%0

500

0.8%

015

00

2.5%

00

00.

0%0

500

0.6%

010

00

0.7%

052

60

1.6%

2011

037

60

3.6%

850

20.

9%0

150

02.

5%0

00

0.0%

1250

421.

3%20

100

441.

1%20

626

442.

1%20

120

376

03.

6%13

100

21.

7%0

150

02.

4%0

00

0.0%

1710

042

1.8%

3120

044

1.8%

3172

644

2.3%

2013

(b)

037

60

3.5

%1

712

52

2.1%

02

00

03

.2%

00

00.

0%24

125

422.

1%41

25

044

2.1%

4182

64

42.

6%

2014

037

60

3.5%

2815

027

3.5%

035

00

5.6%

010

00

4.2%

3915

067

3.2%

6730

094

3.3%

671,

126

943.

8%20

150

376

03.

5%38

190

274.

2%0

650

010

.2%

010

00

4.2%

5521

067

3.9%

9440

094

4.0%

941,

526

945.

0%20

160

376

03.

5%49

273

255.

5%0

650

010

.3%

010

00

4.2%

7137

725

5.1%

120

650

505.

3%12

01,

776

505.

6%20

170

376

03.

5%59

323

256.

4%0

650

010

.3%

010

00

4.2%

8747

725

6.3%

146

800

506.

3%14

61,

926

506.

0%20

180

376

03.

4%71

323

758.

5%0

650

010

.3%

010

00

4.2%

101

527

758.

4%17

285

015

08.

4%17

21,

976

150

6.9%

2019

037

60

3.4%

8337

375

9.4%

065

00

10.4

%0

100

04.

1%11

557

775

9.0%

198

950

150

9.1%

198

2,07

615

07.

2%20

200

376

03.

4%95

448

7510

.7%

065

00

10.3

%0

100

04.

1%13

065

275

9.9%

225

1,10

015

010

.2%

225

2,22

615

07.

6%20

210

376

03.

3%11

344

875

10.8

%0

700

011

.0%

015

00

6.1%

142

652

125

11.5

%25

61,

100

200

11.2

%25

62,

326

200

8.3%

2022

040

90

3.6%

125

515

7512

.0%

070

00

11.0

%0

150

06.

0%17

665

212

511

.6%

301

1,16

720

011

.8%

301

2,42

620

08.

6%20

230

409

03.

6%12

561

575

13.5

%0

700

010

.9%

015

00

6.0%

176

752

125

12.7

%30

11,

367

200

13.1

%30

12,

626

200

9.1%

2024

040

90

3.5%

147

665

7514

.4%

075

050

13.7

%0

150

5011

.1%

198

802

125

13.3

%34

51,

467

200

13.8

%34

52,

776

300

10.2

%20

250

409

03.

5%14

771

575

15.1

%0

800

5014

.3%

015

050

11.1

%19

885

212

513

.8%

345

1,56

720

014

.4%

345

2,92

630

010

.5%

2026

040

90

3.5%

156

765

7515

.9%

085

050

15.0

%0

150

5011

.0%

208

902

125

14.4

%36

41,

667

200

15.0

%36

43,

076

300

10.9

%20

270

409

03.

4%15

681

594

17.3

%0

850

5014

.9%

020

063

14.1

%20

895

214

415

.4%

364

1,76

723

816

.2%

364

3,22

635

011

.6%

2028

040

90

3.4%

169

865

9418

.0%

085

050

14.8

%0

200

6314

.0%

220

1,00

214

415

.9%

389

1,86

723

816

.8%

389

3,32

635

011

.8%

2029

040

90

3.4%

169

865

9417

.9%

085

050

14.7

%0

200

6313

.9%

220

1,00

214

415

.8%

389

1,86

723

816

.7%

389

3,32

635

011

.7%

2030

040

90

3.3%

185

865

9417

.8%

085

050

14.7

%0

200

6313

.8%

236

1,00

214

415

.8%

420

1,86

723

816

.7%

420

3,32

635

011

.7%

(a)

Dat

a ex

clud

es c

onve

ntio

nal (

run-

of-r

iver

) hy

dro

ener

gy a

s a

rene

wab

le s

ourc

e as

it h

as b

een

exc

lud

ed f

rom

ce

rta

in s

tate

an

d p

rop

ose

d fe

de

ral R

PS

crit

eria

.(b

) 20

12/2

013

repr

esen

t th

e in

itial

yea

rs f

or F

eder

al R

PS

/RE

S m

anda

tes

as c

urre

ntly

pro

pose

d by

sev

eral

dra

ft b

ills

befo

re C

ong

ress

. F

urth

er, 2

013

wou

ld r

epre

sent

the

initi

al y

ear

afte

r th

e lik

ely

expi

ratio

n of

Pro

duct

ion

Tax

Cre

dits

(P

TC

) fo

r, p

artic

ular

ly,

win

d re

sour

ces.

E

stab

lishm

ent o

f a

fede

ral r

enew

able

sst

anda

rd w

ould

like

ly e

limin

ate

furt

her

exte

nsio

n of

suc

h P

TC

opp

ortu

nitie

s.

2009

039

30

9.4%

031

00.

6%0

424

04.

9%20

090

499

01.

4%20

100

492

011

.8%

011

10

2.4%

060

20

7.0%

2010

01,

128

02.

9%20

110

591

014

.0%

011

10

2.3%

070

10

7.8%

2011

201,

327

443.

5%20

120

691

015

.8%

011

10

2.2%

080

10

8.7%

2012

311,

527

443.

9%20

13(b

)0

691

015

.7%

011

10

2.2%

080

10

8.6%

2013

411,

627

444.

1%20

140

691

015

.5%

011

10

2.2%

080

10

8.6%

2014

671,

927

945.

0%20

150

691

015

.5%

2531

10

6.5%

251,

001

010

.8%

2015

119

2,52

794

6.5%

2016

069

10

15.4

%25

511

010

.5%

251,

201

012

.8%

2016

145

2,97

750

7.4%

2017

079

10

17.6

%25

611

012

.4%

251,

401

014

.9%

2017

171

3,32

750

8.3%

2018

079

10

17.5

%25

611

012

.3%

251,

401

014

.8%

2018

197

3,37

715

08.

9%20

190

791

017

.4%

2561

10

12.2

%25

1,40

10

14.6

%20

1922

33,

477

150

9.1%

2020

094

10

20.5

%25

761

015

.0%

251,

701

017

.6%

2020

250

3,92

715

010

.2%

2021

094

10

20.4

%25

861

016

.8%

251,

801

018

.5%

2021

281

4,12

720

010

.9%

2022

094

10

20.2

%25

961

018

.5%

251,

901

019

.3%

2022

326

4,32

720

011

.4%

2023

01,

041

022

.2%

2596

10

18.3

%25

2,00

10

20.2

%20

2332

64,

627

200

12.0

%20

240

1,04

10

22.0

%25

1,06

10

20.0

%25

2,10

10

21.0

%20

2437

04,

877

300

13.0

%20

250

1,04

10

21.8

%25

1,16

10

21.7

%25

2,20

10

21.7

%20

2537

05,

127

300

13.5

%20

269

1,14

10

23.8

%34

1,16

10

21.5

%44

2,30

10

22.6

%20

2640

85,

377

300

14.0

%20

279

1,14

10

23.6

%34

1,26

10

23.1

%44

2,40

10

23.4

%20

2740

85,

627

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123

Appendix F, Figure 1, Internal Demand by Company

YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC Summer Winter

2010 6,887 7,008 6,102 5,236 4,677 5,554 5,567 6,005 5,284 5,154 5,750 6,461 6,005 7,0082011 7,087 7,220 6,212 5,290 4,733 5,670 5,587 6,041 5,374 5,187 5,828 6,587 6,041 7,2202012 7,465 7,584 6,726 5,625 5,131 6,070 6,021 6,486 5,737 5,542 6,170 6,954 6,486 7,5842013 7,542 7,662 6,851 5,718 5,197 6,163 6,112 6,589 5,827 5,616 6,272 7,074 6,589 7,6622014 7,603 7,726 6,978 5,789 5,235 6,240 6,183 6,671 5,897 5,656 6,367 7,191 6,671 7,7262015 7,658 7,785 7,097 5,851 5,259 6,301 6,238 6,737 5,949 5,687 6,447 7,304 6,737 7,7852016 7,673 7,803 6,912 5,860 5,283 6,329 6,267 6,768 5,978 5,695 6,461 7,312 6,768 7,8032017 7,710 7,829 7,126 5,906 5,377 6,390 6,322 6,822 6,025 5,791 6,524 7,382 6,822 7,8292018 7,762 7,879 7,174 5,949 5,417 6,443 6,378 6,882 6,080 5,827 6,554 7,427 6,882 7,8792019 7,813 7,931 7,224 5,993 5,463 6,501 6,438 6,947 6,141 5,866 6,593 7,470 6,947 7,9312020 7,842 7,955 7,247 6,011 5,488 6,541 6,480 6,992 6,183 5,889 6,620 7,493 6,992 7,9552021 7,926 8,041 7,127 6,077 5,554 6,618 6,559 7,077 6,260 5,949 6,690 7,564 7,077 8,0412022 7,982 8,097 7,181 6,121 5,605 6,677 6,619 7,143 6,320 5,989 6,738 7,614 7,143 8,0972023 8,008 8,109 7,383 6,185 5,696 6,737 6,673 7,197 6,367 6,085 6,774 7,673 7,197 8,1092024 8,044 8,147 7,418 6,200 5,725 6,785 6,722 7,250 6,415 6,108 6,800 7,699 7,250 8,1472025 8,130 8,234 7,500 6,269 5,789 6,866 6,804 7,339 6,496 6,169 6,875 7,776 7,339 8,2342026 8,185 8,296 7,555 6,308 5,835 6,926 6,866 7,406 6,556 6,207 6,925 7,822 7,406 8,2962027 8,247 8,359 7,420 6,352 5,889 6,992 6,932 7,479 6,622 6,250 6,975 7,874 7,479 8,3592028 8,286 8,402 7,456 6,363 5,931 7,042 6,984 7,534 6,675 6,271 7,025 7,904 7,534 8,4022029 8,333 8,441 7,677 6,467 6,028 7,119 7,055 7,606 6,735 6,388 7,046 7,987 7,606 8,4412030 8,398 8,510 7,740 6,511 6,080 7,187 7,123 7,681 6,802 6,430 7,106 8,045 7,681 8,5102031 8,466 8,579 7,807 6,557 6,133 7,255 7,192 7,756 6,872 6,478 7,163 8,103 7,756 8,5792032 8,508 8,627 7,649 6,566 6,173 7,309 7,248 7,818 6,927 6,504 7,221 8,135 7,818 8,6272033 8,604 8,726 7,741 6,635 6,247 7,399 7,338 7,915 7,015 6,567 7,310 8,222 7,915 8,7262034 8,641 8,751 7,951 6,746 6,346 7,472 7,403 7,983 7,070 6,679 7,397 8,291 7,983 8,7512035 8,720 8,834 8,024 6,798 6,407 7,550 7,483 8,068 7,149 6,728 7,374 8,358 8,068 8,8342036 8,745 8,864 8,056 6,798 6,441 7,605 7,537 8,130 7,204 6,753 7,422 8,381 8,130 8,8642037 8,873 8,995 8,174 6,883 6,524 7,708 7,642 8,243 7,305 6,831 7,534 8,492 8,243 8,9952038 8,955 9,079 8,051 6,935 6,593 7,793 7,726 8,334 7,390 6,886 7,614 8,566 8,334 9,0792039 9,036 9,169 8,132 6,985 6,661 7,875 7,810 8,425 7,471 6,943 7,690 8,639 8,425 9,169

Notes: Load Forecast per J. M. Harris (04/26/10). Demands do not reflect a reduction for PJM marginal losses OR reflect mandated commission approved

and incremental DSM programs for APCo, CSP, I&M, KPCo & OPCo. WPCo load moved from OPCo to APCo 1/2012.


2010 3,422 3,390 3,101 2,766 3,517 3,724 4,139 4,273 3,719 2,958 3,069 3,331 4,273 3,4222011 3,395 3,363 3,097 2,763 3,527 3,736 4,152 4,291 3,743 2,972 3,078 3,337 4,291 3,3952012 3,426 3,392 3,212 2,774 3,577 3,783 4,196 4,333 3,783 2,992 3,210 3,356 4,333 3,4262013 3,474 3,444 3,268 2,827 3,636 3,842 4,260 4,400 3,844 3,036 3,060 3,402 4,400 3,4742014 3,497 3,477 3,294 2,853 3,671 3,874 4,295 4,438 3,873 3,056 3,076 3,424 4,438 3,4972015 3,500 3,488 3,305 2,867 3,693 3,893 4,315 4,463 3,901 3,071 3,087 3,442 4,463 3,5002016 3,499 3,494 3,214 2,877 3,707 3,896 4,326 4,471 3,914 3,074 3,209 3,442 4,471 3,4992017 3,511 3,503 3,309 2,875 3,738 3,926 4,357 4,499 3,946 3,088 3,335 3,464 4,499 3,5112018 3,518 3,521 3,324 2,890 3,762 3,949 4,378 4,521 3,971 3,097 3,345 3,472 4,521 3,5212019 3,531 3,544 3,343 2,908 3,785 3,971 4,397 4,544 3,993 3,108 3,148 3,484 4,544 3,5442020 3,533 3,546 3,347 2,919 3,803 3,977 4,406 4,554 4,002 3,112 3,143 3,486 4,554 3,5462021 3,574 3,599 3,283 2,951 3,838 4,007 4,438 4,578 4,023 3,121 3,270 3,492 4,578 3,5992022 3,589 3,616 3,303 2,968 3,857 4,027 4,465 4,603 4,044 3,132 3,279 3,509 4,603 3,6162023 3,600 3,610 3,392 2,960 3,875 4,050 4,491 4,626 4,067 3,144 3,400 3,530 4,626 3,6102024 3,610 3,613 3,406 2,968 3,896 4,072 4,510 4,636 4,085 3,152 3,199 3,539 4,636 3,6132025 3,640 3,656 3,434 2,994 3,933 4,104 4,551 4,682 4,118 3,176 3,221 3,568 4,682 3,6562026 3,664 3,683 3,454 3,015 3,966 4,133 4,588 4,719 4,147 3,196 3,235 3,591 4,719 3,6832027 3,689 3,708 3,372 3,036 3,998 4,164 4,629 4,759 4,180 3,218 3,359 3,615 4,759 3,7082028 3,706 3,718 3,394 3,054 4,021 4,192 4,663 4,792 4,211 3,233 3,374 3,639 4,792 3,7182029 3,736 3,741 3,506 3,052 4,058 4,235 4,710 4,841 4,250 3,263 3,515 3,676 4,841 3,7412030 3,763 3,769 3,533 3,075 4,094 4,272 4,750 4,887 4,284 3,285 3,340 3,703 4,887 3,7692031 3,795 3,804 3,566 3,104 4,139 4,311 4,800 4,940 4,325 3,257 3,357 3,735 4,940 3,8042032 3,821 3,824 3,475 3,129 4,178 4,345 4,845 4,984 4,360 3,285 3,473 3,759 4,984 3,8242033 3,867 3,880 3,521 3,170 4,229 4,398 4,910 5,048 4,414 3,323 3,508 3,808 5,048 3,8802034 3,899 3,891 3,639 3,208 4,266 4,446 4,964 5,102 4,460 3,364 3,656 3,850 5,102 3,8992035 3,938 3,934 3,676 3,242 4,316 4,497 5,020 5,163 4,512 3,398 3,689 3,890 5,163 3,9382036 3,961 3,945 3,834 3,268 4,362 4,537 5,067 5,216 4,548 3,425 3,516 3,913 5,216 3,9612037 4,022 4,023 3,755 3,315 4,431 4,599 5,144 5,296 4,613 3,473 3,559 3,972 5,296 4,0232038 4,069 4,068 3,678 3,354 4,486 4,656 5,212 5,365 4,670 3,514 3,679 4,017 5,365 4,0692039 4,114 4,120 3,724 3,397 4,541 4,713 5,283 5,434 4,729 3,555 3,715 4,066 5,434 4,120


and incremental DSM programs for APCo, CSP, I&M, KPCo & OPCo.

COLUMBUS SOUTHERN POWER COMPANYMONTHLY PEAK INTERNAL DEMAND - (MW) W/O EMBEDDED DSM

JANUARY 2010 - DECEMBER 2039

APPALACHIAN POWER COMPANYMONTHLY PEAK INTERNAL DEMAND - (MW) W/O EMBEDDED DSM




124



2010 3,817 3,694 3,421 3,237 3,222 4,046 4,436 4,417 3,831 3,233 3,257 3,548 4,436 3,8172011 3,827 3,705 3,432 3,253 3,235 4,065 4,459 4,439 3,851 3,248 3,263 3,556 4,459 3,8272012 3,908 3,784 3,560 3,310 3,332 4,164 4,558 4,538 3,943 3,310 3,372 3,623 4,558 3,9082013 3,975 3,850 3,622 3,375 3,392 4,234 4,634 4,614 4,012 3,366 3,414 3,675 4,634 3,9752014 3,989 3,865 3,638 3,396 3,409 4,247 4,642 4,625 4,027 3,400 3,420 3,707 4,642 3,9892015 4,000 3,876 3,650 3,412 3,422 4,260 4,656 4,640 4,042 3,421 3,425 3,725 4,656 4,0002016 3,998 3,877 3,597 3,422 3,424 4,262 4,656 4,642 4,047 3,438 3,427 3,733 4,656 3,9982017 4,021 3,898 3,669 3,422 3,458 4,292 4,684 4,672 4,076 3,422 3,479 3,685 4,684 4,0212018 4,040 3,919 3,690 3,447 3,487 4,314 4,707 4,696 4,099 3,447 3,491 3,794 4,707 4,0402019 4,062 3,941 3,710 3,471 3,509 4,338 4,731 4,720 4,124 3,473 3,505 3,711 4,731 4,0622020 4,071 3,951 3,721 3,475 3,518 4,352 4,746 4,736 4,139 3,489 3,502 3,719 4,746 4,0712021 4,107 3,986 3,701 3,511 3,547 4,392 4,790 4,780 4,178 3,523 3,533 3,752 4,790 4,1072022 4,130 4,009 3,722 3,537 3,568 4,420 4,823 4,812 4,206 3,548 3,554 3,773 4,823 4,1302023 4,147 4,024 3,788 3,542 3,595 4,450 4,855 4,843 4,232 3,558 3,599 3,782 4,855 4,1472024 4,157 4,033 3,799 3,552 3,610 4,467 4,876 4,864 4,250 3,574 3,596 3,806 4,876 4,1572025 4,194 4,071 3,833 3,581 3,642 4,510 4,924 4,911 4,291 3,609 3,622 3,840 4,924 4,1942026 4,219 4,094 3,857 3,609 3,663 4,541 4,960 4,946 4,321 3,634 3,638 3,863 4,960 4,2192027 4,242 4,118 3,823 3,634 3,683 4,571 4,994 4,980 4,350 3,657 3,658 3,884 4,994 4,2422028 4,259 4,133 3,838 3,661 3,695 4,593 5,020 5,008 4,373 3,678 3,673 3,885 5,020 4,2592029 4,288 4,160 3,918 3,663 3,741 4,636 5,067 5,051 4,410 3,699 3,723 3,934 5,067 4,2882030 4,315 4,188 3,943 3,685 3,765 4,670 5,106 5,090 4,443 3,727 3,740 3,959 5,106 4,3152031 4,344 4,215 3,971 3,715 3,789 4,705 5,146 5,130 4,478 3,755 3,759 3,985 5,146 4,3442032 4,358 4,230 3,928 3,741 3,801 4,728 5,173 5,158 4,501 3,775 3,764 3,999 5,173 4,3582033 4,404 4,274 3,951 3,785 3,838 4,780 5,230 5,214 4,550 3,817 3,804 4,041 5,230 4,4042034 4,431 4,298 4,049 3,787 3,876 4,822 5,277 5,259 4,587 3,836 3,861 4,058 5,277 4,4312035 4,465 4,332 4,080 3,813 3,913 4,863 5,323 5,306 4,627 3,869 3,884 4,104 5,323 4,4652036 4,476 4,344 4,102 3,839 3,926 4,887 5,352 5,335 4,652 3,891 3,884 4,117 5,352 4,4762037 4,526 4,392 4,138 3,885 3,962 4,940 5,411 5,393 4,701 3,932 3,917 4,161 5,411 4,5262038 4,556 4,422 4,084 3,917 3,989 4,978 5,455 5,437 4,739 3,962 3,943 4,189 5,455 4,5562039 4,584 4,450 4,119 3,946 4,011 5,013 5,496 5,478 4,773 3,991 3,967 4,215 5,496 4,584




2010 1,403 1,483 1,270 1,103 977 1,086 1,168 1,260 1,032 1,009 1,185 1,374 1,260 1,4832011 1,467 1,545 1,289 1,111 982 1,106 1,164 1,257 1,047 1,011 1,196 1,395 1,257 1,5452012 1,471 1,543 1,341 1,120 997 1,122 1,169 1,262 1,056 1,021 1,212 1,416 1,262 1,5432013 1,481 1,548 1,372 1,138 1,018 1,144 1,173 1,267 1,076 1,031 1,231 1,448 1,267 1,5482014 1,492 1,549 1,411 1,157 1,023 1,160 1,175 1,272 1,084 1,036 1,258 1,492 1,272 1,5492015 1,507 1,554 1,458 1,181 1,018 1,168 1,177 1,276 1,089 1,040 1,283 1,542 1,276 1,5542016 1,506 1,555 1,402 1,184 1,011 1,168 1,177 1,277 1,090 1,040 1,281 1,541 1,277 1,5552017 1,510 1,559 1,462 1,180 1,021 1,174 1,180 1,277 1,097 1,053 1,340 1,551 1,277 1,5592018 1,517 1,566 1,469 1,187 1,026 1,179 1,186 1,283 1,103 1,056 1,306 1,557 1,283 1,5662019 1,517 1,568 1,474 1,194 1,043 1,184 1,193 1,290 1,110 1,061 1,305 1,558 1,290 1,5682020 1,512 1,565 1,473 1,196 1,039 1,185 1,196 1,294 1,107 1,062 1,299 1,555 1,294 1,5652021 1,520 1,575 1,422 1,207 1,043 1,195 1,206 1,305 1,117 1,071 1,304 1,562 1,305 1,5752022 1,524 1,580 1,430 1,215 1,046 1,203 1,214 1,315 1,126 1,077 1,308 1,567 1,315 1,5802023 1,522 1,580 1,488 1,213 1,062 1,210 1,218 1,316 1,134 1,091 1,378 1,573 1,316 1,5802024 1,522 1,582 1,491 1,216 1,075 1,215 1,225 1,323 1,141 1,093 1,325 1,574 1,323 1,5822025 1,533 1,593 1,503 1,229 1,081 1,226 1,237 1,336 1,146 1,102 1,334 1,584 1,336 1,5932026 1,538 1,601 1,510 1,237 1,085 1,235 1,246 1,348 1,155 1,109 1,338 1,590 1,348 1,6012027 1,545 1,609 1,458 1,245 1,090 1,244 1,256 1,359 1,165 1,115 1,342 1,596 1,359 1,6092028 1,546 1,613 1,463 1,250 1,089 1,250 1,264 1,367 1,173 1,119 1,342 1,599 1,367 1,6132029 1,550 1,617 1,527 1,256 1,113 1,261 1,271 1,372 1,184 1,137 1,363 1,611 1,372 1,6172030 1,557 1,626 1,536 1,264 1,126 1,270 1,281 1,383 1,194 1,142 1,368 1,618 1,383 1,6262031 1,564 1,634 1,545 1,272 1,131 1,279 1,291 1,395 1,196 1,149 1,373 1,625 1,395 1,6342032 1,567 1,639 1,487 1,276 1,129 1,286 1,299 1,403 1,204 1,153 1,375 1,627 1,403 1,6392033 1,579 1,651 1,500 1,287 1,136 1,297 1,312 1,417 1,216 1,162 1,385 1,639 1,417 1,6512034 1,579 1,653 1,564 1,294 1,157 1,307 1,317 1,420 1,227 1,179 1,473 1,648 1,420 1,6532035 1,587 1,663 1,574 1,303 1,166 1,316 1,328 1,433 1,238 1,185 1,410 1,656 1,433 1,6632036 1,583 1,660 1,631 1,301 1,171 1,321 1,334 1,439 1,236 1,186 1,403 1,653 1,439 1,6602037 1,602 1,682 1,593 1,318 1,180 1,336 1,350 1,457 1,251 1,199 1,420 1,671 1,457 1,6822038 1,610 1,692 1,538 1,327 1,186 1,347 1,362 1,471 1,263 1,207 1,428 1,681 1,471 1,6922039 1,619 1,703 1,550 1,338 1,192 1,357 1,374 1,484 1,277 1,215 1,436 1,690 1,484 1,703



MONTHLY PEAK INTERNAL DEMAND - (MW) W/O EMBEDDED DSMJANUARY 2010 - DECEMBER 2039

INDIANA MICHIGAN POWER COMPANYMONTHLY PEAK INTERNAL DEMAND - (MW) W/O EMBEDDED DSM


KENTUCKY POWER COMPANY



125


YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

2010 4,786 4,550 4,375 3,950 4,116 4,709 5,124 5,022 4,656 3,815 4,241 4,332 5,124 4,7862011 4,825 4,603 4,425 3,996 4,148 4,745 5,161 5,059 4,696 3,841 4,280 4,381 5,161 4,8252012 4,487 4,268 4,186 3,728 3,901 4,466 4,846 4,744 4,410 3,614 4,076 4,116 4,846 4,4872013 4,552 4,332 4,254 3,795 3,958 4,528 4,907 4,805 4,470 3,677 3,882 4,174 4,907 4,5522014 4,588 4,370 4,291 3,835 3,992 4,564 4,942 4,841 4,506 3,709 3,911 4,204 4,942 4,5882015 4,609 4,395 4,319 3,868 4,019 4,595 4,972 4,871 4,540 3,737 3,938 4,235 4,972 4,6092016 4,618 4,407 4,289 3,888 4,034 4,609 4,983 4,882 4,553 3,743 4,186 4,237 4,983 4,6182017 4,641 4,426 4,349 3,891 4,062 4,640 5,011 4,908 4,580 3,785 4,282 4,265 5,011 4,6412018 4,655 4,443 4,366 3,911 4,080 4,659 5,029 4,926 4,599 3,797 4,270 4,278 5,029 4,6552019 4,675 4,466 4,389 3,935 4,102 4,685 5,052 4,952 4,624 3,812 4,016 4,295 5,052 4,6752020 4,676 4,468 4,393 3,949 4,110 4,691 5,057 4,957 4,631 3,814 4,013 4,295 5,057 4,6762021 4,715 4,511 4,387 3,986 4,141 4,724 5,091 4,989 4,661 3,835 4,287 4,316 5,091 4,7152022 4,736 4,533 4,410 4,011 4,161 4,747 5,116 5,014 4,684 3,849 4,302 4,335 5,116 4,7362023 4,750 4,541 4,460 4,004 4,180 4,772 5,140 5,036 4,706 3,883 4,389 4,354 5,140 4,7502024 4,753 4,541 4,465 4,011 4,187 4,781 5,150 5,048 4,715 3,882 4,083 4,355 5,150 4,7532025 4,784 4,576 4,496 4,042 4,216 4,814 5,188 5,086 4,747 3,905 4,106 4,384 5,188 4,7842026 4,806 4,598 4,517 4,064 4,238 4,838 5,217 5,113 4,773 3,918 4,118 4,403 5,217 4,8062027 4,829 4,621 4,494 4,088 4,260 4,865 5,249 5,143 4,800 3,934 4,394 4,422 5,249 4,8292028 4,843 4,631 4,509 4,107 4,276 4,884 5,272 5,165 4,821 3,939 4,402 4,436 5,272 4,8432029 4,871 4,656 4,572 4,111 4,305 4,921 5,310 5,200 4,853 3,984 4,477 4,468 5,310 4,8712030 4,893 4,678 4,595 4,132 4,327 4,948 5,338 5,231 4,879 3,999 4,206 4,488 5,338 4,8932031 4,919 4,703 4,621 4,157 4,353 4,977 5,372 5,263 4,908 4,017 4,222 4,510 5,372 4,9192032 4,928 4,709 4,585 4,170 4,366 4,993 5,393 5,283 4,925 4,020 4,491 4,518 5,393 4,9282033 4,968 4,753 4,624 4,210 4,402 5,035 5,440 5,328 4,966 4,048 4,523 4,556 5,440 4,9682034 4,992 4,770 4,682 4,210 4,427 5,068 5,474 5,360 4,996 4,088 4,620 4,582 5,474 4,9922035 5,020 4,796 4,711 4,236 4,453 5,101 5,510 5,395 5,027 4,106 4,615 4,608 5,510 5,0202036 5,027 4,801 4,813 4,251 4,472 5,121 5,535 5,420 5,047 4,115 4,321 4,614 5,535 5,0272037 5,082 4,858 4,773 4,299 4,516 5,171 5,591 5,475 5,097 4,152 4,360 4,663 5,591 5,0822038 5,122 4,896 4,763 4,336 4,553 5,215 5,642 5,523 5,141 4,188 4,669 4,698 5,642 5,1222039 5,155 4,931 4,797 4,369 4,585 5,254 5,677 5,564 5,180 4,212 4,697 4,730 5,677 5,155




2010 20,159 20,044 17,552 16,199 16,053 18,561 20,383 20,821 18,415 15,664 17,143 18,724 20,821 20,1592011 20,437 20,367 17,725 16,322 16,167 18,732 20,473 20,930 18,599 15,758 17,258 18,939 20,930 20,4372012 20,581 20,495 18,870 16,468 16,466 19,014 20,736 21,191 18,843 16,050 17,695 19,168 21,191 20,5812013 20,845 20,764 19,206 16,753 16,706 19,302 21,025 21,495 19,136 16,286 17,506 19,485 21,495 20,8452014 20,990 20,916 19,446 16,927 16,821 19,455 21,176 21,663 19,295 16,391 17,685 19,711 21,663 20,9902015 21,095 21,026 19,655 17,069 16,892 19,564 21,291 21,800 19,421 16,481 17,839 19,930 21,800 21,0952016 21,118 21,064 18,644 17,117 16,946 19,612 21,341 21,852 19,482 16,497 18,073 19,936 21,852 21,1182017 21,193 21,134 19,727 17,164 17,164 19,770 21,477 21,984 19,607 16,728 18,683 20,096 21,984 21,1932018 21,294 21,245 19,835 17,275 17,261 19,886 21,597 22,111 19,735 16,806 18,533 20,189 22,111 21,2942019 21,403 21,370 19,952 17,391 17,368 20,015 21,729 22,258 19,874 16,894 18,211 20,273 22,258 21,4032020 21,440 21,403 19,996 17,447 17,418 20,078 21,799 22,338 19,949 16,933 18,239 20,304 22,338 21,4402021 21,651 21,631 19,168 17,627 17,584 20,259 21,996 22,533 20,126 17,056 18,630 20,434 22,533 21,6512022 21,769 21,753 19,292 17,739 17,699 20,390 22,151 22,690 20,266 17,140 18,727 20,541 22,690 21,7692023 21,806 21,771 20,310 17,785 17,891 20,538 22,285 22,819 20,377 17,345 19,323 20,670 22,819 21,8062024 21,867 21,826 20,378 17,832 17,948 20,637 22,391 22,926 20,478 17,376 18,623 20,707 22,926 21,8672025 22,062 22,037 20,566 18,006 18,108 20,828 22,613 23,159 20,676 17,514 18,781 20,880 23,159 22,0622026 22,193 22,181 20,691 18,118 18,229 20,977 22,786 23,337 20,836 17,603 18,882 20,988 23,337 22,1932027 22,334 22,321 19,807 18,237 18,362 21,131 22,967 23,523 21,000 17,697 19,314 21,103 23,523 22,3342028 22,423 22,406 19,892 18,304 18,460 21,251 23,113 23,669 21,135 17,764 19,397 21,181 23,669 22,4232029 22,532 22,509 20,982 18,443 18,693 21,463 23,317 23,868 21,300 18,013 19,816 21,377 23,868 22,5322030 22,680 22,666 21,129 18,558 18,825 21,630 23,504 24,068 21,470 18,106 19,340 21,506 24,068 22,6802031 22,844 22,832 21,290 18,690 18,971 21,803 23,705 24,282 21,653 18,194 19,458 21,644 24,282 22,8442032 22,938 22,926 20,342 18,750 19,075 21,929 23,863 24,442 21,792 18,260 19,937 21,715 24,442 22,9382033 23,177 23,180 20,564 18,950 19,279 22,169 24,136 24,718 22,038 18,425 20,137 21,933 24,718 23,1802034 23,267 23,242 21,650 19,096 19,515 22,378 24,335 24,913 22,203 18,662 20,795 22,106 24,913 23,2672035 23,456 23,439 21,836 19,243 19,680 22,580 24,564 25,156 22,417 18,797 20,705 22,269 25,156 23,4562036 23,515 23,492 22,106 19,286 19,779 22,716 24,725 25,330 22,558 18,862 20,095 22,322 25,330 23,5152037 23,834 23,831 22,198 19,526 20,012 22,989 25,036 25,653 22,840 19,066 20,348 22,594 25,653 23,8342038 24,040 24,037 21,327 19,686 20,206 23,210 25,293 25,918 23,073 19,233 20,960 22,776 25,918 24,0402039 24,237 24,253 21,520 19,841 20,390 23,425 25,544 26,172 23,298 19,381 21,132 22,956 26,172 24,253




AEP SYSTEM - (EAST)MONTHLY PEAK INTERNAL DEMAND - (MW) W/O EMBEDDED DSM


OHIO POWER COMPANYMONTHLY PEAK INTERNAL DEMAND - (MW) W/O EMBEDDED DSM



126

Appendix F, Figure 4, Internal Energy by Company

APPALACHIAN POWER COMPANY

MONTHLY ENERGY REQUIREMENT - (GWH) W/O EMBEDDED DSM


YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YEAR

2010 3,825 3,239 3,097 2,671 2,629 2,847 3,064 3,100 2,722 2,748 2,974 3,529 36,444

2011 3,851 3,249 3,095 2,652 2,624 2,860 3,078 3,127 2,721 2,735 2,967 3,548 36,508

2012 4,110 3,593 3,326 2,864 2,857 3,088 3,337 3,386 2,937 2,972 3,181 3,767 39,418

2013 4,172 3,527 3,368 2,912 2,898 3,130 3,396 3,431 2,989 3,014 3,217 3,827 39,881

2014 4,218 3,564 3,404 2,933 2,911 3,169 3,434 3,461 3,025 3,031 3,235 3,873 40,259

2015 4,248 3,591 3,433 2,944 2,915 3,202 3,461 3,490 3,045 3,033 3,255 3,906 40,523

2016 4,249 3,717 3,434 2,945 2,935 3,217 3,461 3,522 3,059 3,040 3,284 3,912 40,776

2017 4,300 3,631 3,469 2,970 2,975 3,248 3,496 3,559 3,083 3,081 3,312 3,938 41,062

2018 4,331 3,657 3,490 3,002 3,004 3,269 3,535 3,589 3,104 3,116 3,334 3,965 41,396

2019 4,364 3,685 3,512 3,039 3,033 3,293 3,576 3,613 3,140 3,148 3,354 4,002 41,760

2020 4,382 3,817 3,540 3,058 3,037 3,330 3,599 3,630 3,171 3,162 3,370 4,028 42,126

Notes: Load Forecast per J. M. Harris (04/26/10). Energy does not reflect a reduction for PJM marginal losses OR reflect mandated commission approved

and incremental DSM programs for APCo, CSP, I&M, KPCo & OPCo. WPCo load moved from OPCo to APCo 1/2012.

COLUMBUS SOUTHERN POWER COMPANY




2010 2,027 1,788 1,839 1,618 1,685 1,880 2,081 2,056 1,736 1,692 1,743 1,985 22,130

2011 2,019 1,779 1,838 1,611 1,691 1,883 2,080 2,070 1,744 1,702 1,745 1,986 22,147

2012 2,049 1,863 1,868 1,633 1,719 1,898 2,110 2,092 1,751 1,732 1,747 1,991 22,453

2013 2,081 1,830 1,898 1,666 1,746 1,922 2,149 2,116 1,784 1,760 1,763 2,026 22,739

2014 2,094 1,844 1,918 1,679 1,752 1,941 2,165 2,125 1,802 1,772 1,764 2,046 22,902

2015 2,091 1,847 1,932 1,684 1,752 1,953 2,173 2,134 1,811 1,775 1,775 2,060 22,988

2016 2,086 1,909 1,906 1,681 1,759 1,955 2,162 2,150 1,812 1,773 1,815 2,059 23,068

2017 2,107 1,861 1,924 1,689 1,776 1,967 2,177 2,161 1,818 1,790 1,819 2,064 23,153

2018 2,113 1,869 1,930 1,701 1,784 1,968 2,190 2,168 1,820 1,802 1,819 2,071 23,235

2019 2,120 1,877 1,939 1,715 1,790 1,970 2,205 2,169 1,832 1,809 1,817 2,084 23,329

2020 2,121 1,933 1,956 1,719 1,782 1,983 2,208 2,167 1,840 1,807 1,810 2,091 23,417


and incremental DSM programs for APCo, CSP, I&M, KPCo & OPCo OR estimated Ohio Choice customer load migration.

INDIANA MICHIGAN POWER COMPANY




2010 2,244 2,038 2,094 1,897 1,918 2,116 2,314 2,327 2,030 1,973 1,976 2,229 25,157

2011 2,260 2,044 2,104 1,894 1,935 2,125 2,313 2,348 2,038 1,982 1,982 2,226 25,251

2012 2,322 2,166 2,148 1,943 1,999 2,167 2,381 2,407 2,070 2,056 2,023 2,259 25,941

2013 2,363 2,128 2,177 1,988 2,033 2,194 2,432 2,436 2,117 2,092 2,045 2,305 26,308

2014 2,375 2,140 2,192 2,002 2,036 2,216 2,443 2,437 2,141 2,106 2,046 2,326 26,458

2015 2,373 2,147 2,212 2,010 2,033 2,235 2,450 2,446 2,151 2,104 2,062 2,335 26,559

2016 2,364 2,223 2,215 2,001 2,048 2,239 2,430 2,473 2,154 2,096 2,086 2,333 26,663

2017 2,404 2,166 2,236 2,009 2,078 2,256 2,449 2,493 2,162 2,128 2,101 2,333 26,815

2018 2,419 2,179 2,240 2,033 2,094 2,259 2,475 2,507 2,165 2,155 2,111 2,345 26,982

2019 2,435 2,192 2,245 2,058 2,107 2,262 2,501 2,509 2,191 2,170 2,113 2,369 27,153

2020 2,440 2,264 2,266 2,066 2,090 2,292 2,509 2,506 2,211 2,165 2,116 2,386 27,311





127

Appendix F, Figure 5, Internal Energy by Company

KENTUCKY POWER COMPANY




2010 795 690 670 582 572 599 623 657 569 570 636 753 7,715

2011 797 690 668 578 570 601 625 660 568 566 633 752 7,708

2012 800 713 667 577 570 602 628 663 568 566 632 754 7,740

2013 809 698 672 578 570 606 635 669 572 566 634 762 7,771

2014 819 705 678 577 567 609 637 670 572 563 635 771 7,802

2015 828 711 683 574 563 609 638 672 571 558 636 779 7,823

2016 827 733 681 574 565 611 638 675 573 559 640 778 7,854

2017 833 715 686 578 570 615 643 680 577 564 643 782 7,886

2018 837 718 688 582 574 618 647 683 580 568 645 785 7,926

2019 840 721 692 587 578 622 653 687 585 573 648 788 7,974

2020 840 743 695 589 580 626 655 689 588 574 649 790 8,019



OHIO POWER COMPANY




2010 2,798 2,513 2,631 2,327 2,341 2,513 2,722 2,747 2,411 2,364 2,450 2,691 30,508

2011 2,837 2,538 2,664 2,335 2,375 2,533 2,727 2,784 2,428 2,388 2,471 2,704 30,785

2012 2,650 2,441 2,470 2,175 2,229 2,351 2,567 2,601 2,241 2,256 2,281 2,496 28,758

2013 2,687 2,387 2,496 2,222 2,259 2,371 2,616 2,620 2,286 2,290 2,293 2,539 29,066

2014 2,702 2,404 2,522 2,242 2,263 2,405 2,636 2,624 2,321 2,306 2,292 2,568 29,286

2015 2,698 2,415 2,554 2,256 2,262 2,435 2,649 2,642 2,338 2,308 2,316 2,585 29,457

2016 2,687 2,504 2,545 2,245 2,285 2,442 2,624 2,680 2,341 2,299 2,363 2,577 29,592

2017 2,728 2,433 2,564 2,247 2,315 2,455 2,641 2,696 2,338 2,330 2,369 2,566 29,682

2018 2,738 2,440 2,560 2,269 2,325 2,447 2,665 2,702 2,333 2,353 2,367 2,574 29,772

2019 2,749 2,450 2,561 2,294 2,331 2,446 2,693 2,697 2,357 2,363 2,356 2,597 29,895

2020 2,745 2,522 2,589 2,297 2,302 2,478 2,693 2,685 2,377 2,347 2,348 2,612 29,996



WPCo load moved from OPCo to APCo 1/2012.

AEP SYSTEM - (EAST)




2010 11,689 10,268 10,331 9,096 9,144 9,956 10,803 10,887 9,468 9,347 9,779 11,187 121,954

2011 11,763 10,300 10,369 9,069 9,196 10,003 10,823 10,990 9,499 9,372 9,799 11,217 122,399

2012 11,931 10,776 10,479 9,191 9,373 10,106 11,024 11,149 9,568 9,582 9,864 11,267 124,310

2013 12,112 10,570 10,611 9,366 9,505 10,222 11,228 11,272 9,747 9,723 9,951 11,459 125,765

2014 12,208 10,657 10,713 9,433 9,528 10,340 11,315 11,317 9,862 9,778 9,971 11,585 126,706

2015 12,237 10,711 10,814 9,469 9,525 10,436 11,371 11,384 9,917 9,778 10,044 11,664 127,349

2016 12,214 11,086 10,782 9,446 9,592 10,465 11,314 11,499 9,938 9,767 10,188 11,659 127,949

2017 12,372 10,807 10,878 9,492 9,716 10,541 11,406 11,589 9,976 9,893 10,244 11,682 128,595

2018 12,438 10,862 10,908 9,587 9,780 10,561 11,512 11,648 10,002 9,993 10,276 11,739 129,305

2019 12,507 10,925 10,949 9,693 9,840 10,592 11,627 11,676 10,105 10,063 10,288 11,839 130,104

2020 12,526 11,280 11,046 9,728 9,792 10,708 11,663 11,678 10,188 10,054 10,292 11,907 130,863



WPCo load moved from OPCo to APCo 1/2012.



128

Appendix G, Figure 1, DSM by Company

GWh MW GWh MW GWh MW GWh MW GWh MW GWh MW2010 0 0 0 0 2010 92 16 46 8 2010 73 14 37 72011 193 27 193 27 2011 270 47 181 30 2011 217 42 145 272012 293 40 293 40 2012 500 88 370 61 2012 405 79 299 552013 395 55 395 55 2013 765 134 572 95 2013 622 122 465 862014 498 76 498 76 2014 1,070 188 782 129 2014 873 171 638 1182015 603 80 603 80 2015 1,382 243 980 162 2015 1,130 221 802 1482016 604 80 604 80 2016 1,682 295 1,139 188 2016 1,379 269 935 1722017 605 79 605 79 2017 1,985 348 1,259 208 2017 1,632 319 1,037 1922018 606 79 606 79 2018 2,289 402 1,351 223 2018 1,887 370 1,117 2062019 606 79 606 79 2019 2,901 509 1,572 260 2019 2,403 471 1,305 2412020 606 78 606 78 2020 3,480 609 1,876 309 2020 2,892 566 1,567 289

GWh MW GWh MW GWh MW GWh MW GWh MW GWh MW2010 0 0 0 0 2010 0 0 0 0 2010 0 0 0 02011 0 0 0 0 2011 0 0 0 0 2011 0 0 0 02012 0 0 0 0 2012 0 0 0 0 2012 0 0 0 02013 0 0 0 0 2013 0 0 0 0 2013 0 0 0 02014 67 6 67 6 2014 15 3 15 3 2014 31 6 31 62015 116 25 116 25 2015 28 5 28 5 2015 66 14 66 142016 142 30 142 30 2016 39 7 39 7 2016 100 21 100 212017 167 36 167 36 2017 50 9 50 9 2017 135 28 135 282018 193 41 193 41 2018 60 11 60 11 2018 170 35 170 352019 193 41 193 41 2019 60 11 60 11 2019 170 35 170 352020 193 41 193 41 2020 60 11 60 11 2020 170 35 170 35


GWh MW GWh MW GWh MW GWh MW GWh MW GWh MW2010 0 0 0 0 2010 92 16 46 8 2010 73 14 37 72011 193 57 193 57 2011 270 71 181 54 2011 217 64 145 482012 293 101 293 101 2012 500 135 370 109 2012 405 122 299 982013 395 162 395 162 2013 765 218 572 178 2013 622 196 465 1612014 565 236 565 236 2014 1,085 310 797 251 2014 904 284 669 2312015 719 289 719 289 2015 1,410 391 1,008 310 2015 1,196 363 868 2902016 746 294 746 294 2016 1,721 445 1,178 338 2016 1,480 418 1,035 3212017 772 298 772 298 2017 2,034 500 1,309 360 2017 1,767 475 1,172 3472018 799 303 799 303 2018 2,349 556 1,412 378 2018 2,057 533 1,287 3702019 799 304 799 304 2019 2,961 663 1,632 414 2019 2,572 634 1,475 4052020 799 303 799 303 2020 3,540 763 1,936 464 2020 3,062 729 1,736 452

IVVC IVVCInstalled Net

Demand Response


Installed Net

APCo (Includes Wheeling and Kingsport)

Installed Net

Demand Response

Energy EfficiencyInstalled Net

IVVC

Ohio Power


Installed Net


Columbus Southern Power


Installed Net





129

Appendix G, Figure 2, DSM by Company

GWh MW GWh MW GWh MW GWh MW GWh MW GWh MW2010 2 0 1 0 2010 66 8 8 2 2010 233 38 91 162011 47 7 43 6 2011 173 26 120 17 2011 900 149 683 1072012 73 10 66 10 2012 321 49 238 34 2012 1,592 266 1,266 2002013 99 14 90 13 2013 505 79 375 55 2013 2,385 404 1,897 3042014 126 17 114 17 2014 725 111 528 75 2014 3,294 563 2,560 4162015 154 20 138 20 2015 980 143 692 94 2015 4,249 708 3,215 5052016 157 20 139 20 2016 1,269 180 860 113 2016 5,091 844 3,676 5732017 159 20 139 20 2017 1,590 221 1,029 133 2017 5,971 988 4,069 6312018 161 20 139 20 2018 1,943 266 1,194 151 2018 6,887 1,136 4,408 6802019 163 20 140 20 2019 2,310 313 1,344 168 2019 8,383 1,392 4,967 7682020 165 20 140 20 2020 2,344 319 1,414 176 2020 9,487 1,593 5,602 873



GWh MW GWh MW GWh MW GWh MW GWh MW GWh MW2010 2 0 1 0 2010 66 8 8 2 2010 233 38 91 162011 47 13 43 13 2011 173 44 120 35 2011 900 249 683 2072012 73 22 66 22 2012 321 86 238 70 2012 1,592 466 1,266 4002013 99 35 90 35 2013 505 143 375 118 2013 2,385 754 1,897 6542014 144 52 132 52 2014 730 202 533 167 2014 3,429 1,084 2,696 9362015 184 64 168 64 2015 993 255 705 205 2015 4,502 1,361 3,468 1,1582016 191 65 173 65 2016 1,292 293 883 226 2016 5,429 1,514 4,015 1,2442017 198 66 178 66 2017 1,623 336 1,061 247 2017 6,394 1,676 4,493 1,3192018 205 67 183 67 2018 1,985 383 1,236 268 2018 7,395 1,842 4,917 1,3852019 207 67 183 67 2019 2,352 430 1,386 285 2019 8,891 2,098 5,475 1,4742020 209 67 183 67 2020 2,386 435 1,456 293 2020 9,996 2,298 6,111 1,578

IVVC

Kentucky Power


IVVCInstalled Net



Indiana Michigan


IVVCInstalled Net



AEP East



Installed Net




130

Appendix H, Ohio Choice by Company

GWh

SUMMER

Peak MW GWh

SUMMER

Peak MW GWh

SUMMER

Peak MW

2010 0 0 2010 0 2010 0 0

2011 139 28 2011 25 4 2011 164 32

2012 326 55 2012 71 12 2012 397 67

2013 454 76 2013 118 19 2013 572 95

2014 582 98 2014 164 26 2014 746 124

2015 780 132 2015 260 42 2015 1,041 176

2016 1,037 172 2016 374 61 2016 1,411 232

2017 1,293 214 2017 467 75 2017 1,760 291

2018 1,550 255 2018 559 90 2018 2,109 347

2019 1,806 298 2019 652 104 2019 2,458 405

2020 2,062 341 2020 745 119 2020 2,807 460

Columbus Southern Power Ohio Power AEP-East

Ohio Customer Choice Ohio Customer Choice Ohio Customer Choice



131

Appendix I, Renewable Energy Technology Screening

Type Energy Source $/MWhLandfill Gas3.20925Combustion Turbine Gas -52.68Incremental Hydro Hydro -37.95New 24 MW Hydro Hydro -10.56Anaerobic Digester0.173270566491537Int. Comb. Engine Gas -4.74Anaerobic DigesterDairy CowInt. Comb. Engine Anaerobic Digester -4.74100 MW Wind Farm 1 SPP PTC SPP PTC 44.29100 MW Wind Farm 2, PJM PTC PJM PTC 45.93Geothermal Geothermal 69.70100 MW Wind Farm SPP, no PTC SPP no PTC 71.38100 MW Wind Farm PJM, no PTC PJM no PTC 73.13New 2 MW Hydro Hydro 102.56McKinsey 2020 Solar - West (nth of a kind) Solar 152.51McKinsey 2020 Solar - East (nth of a kind) Solar 203.34Solar Installation 10 MW fixed Tilt thin film a-Si Solar 226.85SoCalEd 1 MW rooftop Solar 233.36SoCalEd 2 MW rooftop Solar 317.88

Levelized Cost of Renewables versus Avoided Production Cost



132

Appendix J, Capacity Additions by Company

CCCT

*D

CC2

Solar

Wind

**CC

CT*

D CC

2So

larW

ind**

CCCT

*D

CC2

Solar

Wind

**CC

CT*

D CC

2So

larW

ind**

CCCT

*D

CC2

Solar

Wind

**CC

CT*

D CC

2So

larW

ind**

2010

2010

/110

00

296

2.01

00

00

2.01

00

011

90.0

00

00

00.0

00

00

00.0

00

00

178

0.00

2011

2011

/120

00

150

2.00

00

00

0.00

00

075

1.00

00

00

0.00

00

00

0.00

00

075

1.00

2012

2012

/130

00

150

2.00

00

00

0.00

00

060

0.50

00

00

1.00

00

00

0.00

00

090

0.50

2013

2013

/140

01

380

6.00

00

10

0.00

00

015

20.5

00

00

03.0

00

00

02.0

00

00

228

0.50

2014

2014

/150

00

380

8.00

00

00

0.00

00

015

20.8

00

00

06.0

00

00

00.0

00

00

228

1.20

2015

2015

/160

00

380

5.00

00

00

0.00

00

015

21.6

70

00

00.0

00

00

00.0

00

00

228

3.33

2016

2016

/170

00

380

3.00

00

00

0.00

00

015

21.0

00

00

00.0

00

00

00.0

00

00

228

2.00

2017

2017

/180

40

380

1.00

04

00

0.00

00

017

10.0

00

00

00.0

00

00

00.0

00

00

209

1.00

2018

2018

/190

40

380

2.00

02

00

0.00

00

017

11.0

00

00

00.0

00

20

00.0

00

00

209

1.00

2019

2019

/200

00

380

3.00

00

00

0.00

00

017

11.5

00

00

00.0

00

00

00.0

00

00

209

1.50

2020

2020

/210

00

450

2.00

00

00

0.00

00

027

00.0

00

00

01.0

00

00

01. 0

00

00

180

0.00

2021

2021

/220

40

650

2.00

02

00

0.67

00

016

31.3

30

00

00.0

00

20

00.0

00

00

488

0.00

2022

2022

/230

00

04.0

00

00

00.0

00

00

02.0

00

00

00.0

00

00

00.0

00

00

02.0

0

2023

2023

/241

00

650

3.00

10

00

0.00

00

032

51.0

00

00

01.0

00

00

00.0

00

00

325

1.00

2024

2024

/250

00

03.0

00

00

00.0

00

00

01.0

00

00

01.0

00

00

00.0

00

00

01.0

0

2025

2025

/260

00

272

3.00

00

00

0.00

00

013

61.0

00

00

01.0

00

00

00.0

00

00

136

1.00

2026

2026

/271

00

03.0

01

00

00.0

00

00

01.0

00

00

00.0

00

00

01.0

00

00

01.0

0

2027

2027

/280

00

363

2.00

00

00

0.00

00

018

11.0

00

00

00.0

00

00

00.0

00

00

181

1.00

2028

2028

/290

00

00.0

00

00

00.0

00

00

00.0

00

00

00.0

00

00

00.0

00

00

00.0

0

2029

2029

/300

00

453

0.00

00

00

0.00

00

022

70.0

00

00

00.0

00

00

00.0

00

00

227

0.00

2030

2030

/310

40

00.0

00

40

00.0

00

00

00.0

00

00

00.0

00

00

00.0

00

00

00.0

0

CCCT

D CC

2So

larW

ind**

611

7954

00.0

6950

669

8662

50.0

6950

* To q

ualify

for S

umme

r ava

ilabil

ity st

atus a

reso

urce m

ust b

e ava

ilable

by Ju

ne 1s

t of th

at ye

ar.

** W

ind re

sourc

es m

ust b

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pleted

by D

ecem

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f the p

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r to qu

alify

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ilabil

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atus.

A un

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ed av

ailab

le for

the S

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ust b

e com

pleted

no la

ter th

an 12

/31/20

09

OPCo

Capa

city (

MW/U

nit)

APCo

CSP

I&M

KPCo

AEP

Summ

er*W

inter

Summ

er

Wint

er

Exten

ded

Plann

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Perio

d

10-Y

ear

IRP

Perio

d



133

Appendix K, Load Forecast Modeling

Process Summary

AEP utilizes a collaborative process to develop load forecasts. Customer representatives and other operating company personnel routinely provide input on customers (larger customers in particular) and economic conditions. Taking this input into account, the AEP Economic Forecasting group analyzes data, develops and utilizes economic and load forecast data and models, and computes load forecasts. Economic Forecasting and operating company management team members review and discuss the analytical results. The groups work together to obtain the final forecast results. Forecast updates are considered at least two times a year (or more often if deemed necessary).

The electric energy and demand forecast modeling process is the accumulation of three specific forecast model processes as reflected in Exhibit A-8. The first process models the consumption of electricity at the aggregated customer premise level. These aggregated levels are the FERC revenue classifications of residential, commercial, industrial, other, and municipals and cooperatives. It involves modeling both the short- and long-term sales. The second process contains models that derive hourly load estimates from blended short- and long-term sales, estimates of energy losses for distribution and transmission, and class and end-use load shapes. The aggregate revenue class sales and energy losses is generally called “net internal energy requirements.” The third process reconciles historical net internal energy requirements and seasonal peak demands through a load factor analysis which results in the load forecast.

The FERC revenue classes of residential, commercial, industrial, other and municipal and cooperatives are analyzed and forecasted separately. This categorization of customers’ premise meter readings allows for customers with like electrical consumption characteristics and behaviors to be

Exhibit A-8

1. Monthly Sales Forecast(by FERC Revenue Classes)

Short & Long Term

2. Hourly Demand Models(Load Shapes / Losses)

3. Net Internal Energy Requirements& Demand Forecast

Load & Demand Forecast Process – Sequential Steps



134

modeled together. Similarly, utilizing separate short and long-term sales forecast models capitalizes on the strengths of each methodology.

Energy Sales Modeling

The short-term forecasts are developed utilizing autoregressive integrated moving average (ARIMA) models that incorporate weather and binary variables. Heating and cooling degree-days are the weather variables included in the model development. The short-term forecast period extends for up to 18 months on a monthly basis. These models are utilized to forecast all FERC classes and a number of large individual customers.

The long-term forecasts are developed utilizing a combination of econometric and Statistically Adjusted End-Use (SAE) models. The SAE models were developed by Itron Inc. Energy Forecasting unit. The process starts with an economic forecast provided by Moody’s Economy.com for the United States as a whole, each state, and regions within each state. These forecasts include forecasts of employment, population, and other demographic and financial variables. The long-term forecast incorporates the economic forecast and other inputs to produce a forecast of kWh sales. Other inputs include regional and national economic and demographic conditions, energy prices, weather data, and customer-specific information.

AEP uses processes that take advantage of the relative strengths of each method. The regression models with time series error terms use the latest available sales and weather information to represent the variation in sales on a monthly basis for short-term applications. While these models provide advantages in the short run, without specific ties to economic factors, they are limited in capturing the structural trends in the electricity consumption that are important for the longer term planning. The long-term process, with its explicit ties to economic and demographic factors, tends to be structured for longer-term decisions.

Residential Sales

For the residential sector, the number of residential customers and usage per customer are modeled separately, and combined to forecast residential energy sales. Residential customers were modeled as a function of mortgage rates, service area employment, and lagged residential customers. Average residential usage is modeled using the SAE model. SAE models are econometric models with features of end-use models included to specifically account for energy efficiency impacts, such as those included in the Energy Policy Act of 2005. SAE models start with the construction of structured end-use variables that embody end-use trends, including equipment saturation levels and efficiency. Factors are also included to account for changes in energy prices, household size, home size, income, and weather conditions. The statistical part of the SAE model is the regression used to estimate the relationship between observed customer usage and the structured end-use variables. The result is a model that has implicit end-use structure, but is econometric in the estimation. The forecast of residential energy sales is the product of residential customers and residential usage.



135

Commercial Sales

The commercial energy sales model is also an SAE model. In the commercial class, total energy sales are modeled. The primary economic drivers are service area commercial output (GDP), commercial electricity price, state commercial natural gas price and heating and cooling degree-days.

Industrial Sales

The industrial energy sales are forecast in total for the class. Where applicable, the mine power sectors sales are separated before modeling. For the total or total less mine power, energy sales are a function of selected Federal Reserve Board industrial production indexes, regional employment; and electricity and natural gas prices. Where relevant, the mine power energy sales are modeled as a function of state coal production, regional mining employment and mine power electricity price. Customer-specific information such as expansions, contractions and additions and informed judgment are all utilized in producing the forecasts.

Other Sales

Other ultimate sales are generally comprised of public street and highway lighting, municipal pumping, and other sales to public authorities sectors. The public street and highway lighting energy sales are modeled as a function of service area employment. The other sales to public authorities are related to service area employment and heating and cooling degree-days. The other sales forecast is the sum of these forecasts.

Municipal and Cooperatives

The municipal and cooperatives included in internal load are sales to cooperatives, municipals, private systems and state agencies. These are forecast by individual customer and generally are a function of service area employment and heating and cooling degree days.

Blending Short and Long-Term Sales

Forecast values for 2010 are taken from the short-term process. Forecast values for 2011 are obtained by blending the results from the short-term and long-term models. The blending process combines the results of the short-term and long-term models by assigning weights to each result and systematically changing the weights so that by the end of 2011 the entire forecast is from the long-term models. This blending allows for a smooth transition between the two separate processes, minimizing the impact of any differences in the results.

Energy Losses

Energy is lost in the transmission and distribution of the product. This loss of energy from the source of production to consumption at the premise is measured as the average ratio of all FERC revenue class energy sales measured at the premise meter to the net internal energy requirements metered at the source. In modeling, company loss study results are incorporated to apply losses to each revenue class.



136

Net Internal Energy Requirements

Net internal energy requirement is the sum of the FERC revenue class sales resulting from the blending process and energy losses.

Demand Forecast Model

The demand forecast model is a series of algorithms for allocating the monthly blended FERC revenue class sales to hourly demand. The inputs into forecasting hourly demand are blended FERC revenue class sales, energy loss multipliers, weather, 24-hour load profiles and calendar information.

The weather profiles are developed from representative weather stations in the service area. Twelve monthly profiles of average daily temperature that best represent the cooling and heating degree-days of the specific geography are taken from the last 30 years of historical values. The consistency of these profiles ensures the appropriate diversity of the company loads.

The 24-hour load profiles are developed from historical hourly company or jurisdictional load and end-use or revenue class hourly load profiles. The load profiles were developed from segregating, indexing and averaging hourly profiles by season, day types (weekend, midweek and Monday/Friday) and average daily temperature ranges. The end-use and class profiles were obtained from Iron, Inc. Energy Forecasting load shape library and modeled to represent each company or jurisdiction service area.

In forecasting, the weather profiles and calendars dictate which profile to apply and the sales plus losses results dictate the volume of energy under the profile. In the end, the profiles are benchmarked to the aggregate energy and seasonal peaks through the adjustments to the hourly load duration curves of the annual 8760 hourly values. These 8760 hourly values per year are the forecast load of the individual companies of AEP that can be aggregated by hour to represent load across the spectrum from end-use or revenue classes to total AEP-PJM, AEP-SPP or total AEP system. Net internal energy requirements are the sum of these hourly values to a total company energy need basis. Company peak demand is the maximum of the hourly values from a stated period (month, season or year).



137

Appendix L, Capacity Resource Modeling (Strategist) and Levelized Busbar Costs

The overriding objective of the modeling effort was to recommend an optimum system expansion plan, not only from a least-cost perspective but also from the perspectives of risk profile, achievability, and affordability. The analytical model served as the foundation from which all of the perspectives were examined and recommendations made. The process will be continually refined as experience is gained to take into account emerging issues identified by supporting work groups and management.

The Strategist Model

The Strategist resource-planning model, developed by Ventyx, allows a user to determine the least-cost resource mix for its system (in this case, AEP’s East and West zones) from a user-defined set of resource technologies, under prescribed sets of constraints and assumptions. Strategist defines the “least-cost resource mix” as the combination of resource additions that produces the lowest overall system pre-tax cost (revenue requirement) inclusive of:

New resource capital carrying cost and fixed O&M

Environmental retrofits

o New-build capacity

o Capacity (market) purchase costs

o Total system-wide fuel costs (new-build and existing capacity)

o Cost of system-wide (replacement) emission allowances (SO2, NOx, CO2)

o Net (market) “system transaction” cost or revenue (i.e. third-party energy purchases and/or sales).

Strategist allows all aspects of an integrated resource planning study to be considered with the depth and accuracy required for informed decision-making. Hourly chronological load patterns are recognized, detailed production costing logic is utilized, and the system employs a dynamic programming algorithm to develop the “optimal” and large suites of “sub-optimal” portfolios of capacity addition alternatives over a user-defined study period.

Strategist uses several modules (LFA, GAF, PROVIEW) that work in unison to simulate the operation of the generating system, including new resource additions that may be needed to meet future demand growth. These modules calculate the costs of serving a utility system’s capacity and energy needs over the defined study period. The Load Forecast Adjustment module (LFA) is used to represent the utility’s hourly demand and energy forecast. The Generation and Fuel module (GAF) works with the LFA to simulate the operation of a utility’s generating units and any interaction with external markets. The PROVIEW module pulls information from the LFA and GAF modules as well as other generation alternative data to determine the least-cost resource plan for the utility system under prescribed sets of constraints and assumptions.

Strategist develops an initial “macro” (zone-specific) least-cost resource mix for a system by incorporating a wide variety of expansion planning assumptions including:

Characteristics (e.g. capital cost, construction period, operating life) of resource addition alternatives that are available to meet future capacity needs



138

Operating parameters (e.g. capacity ratings, heat rates, forced outage rates, etc) of existing and new units

Fuel prices

Prices of external market energy, capacity, and emission allowances

Reliability constraints (e.g. minimum reserve margin targets, loss of load hours, unserved energy)

Emission limits and environmental compliance options

All of these assumptions, and others, are considered in order to develop an integrated plan that best suits the utility system being analyzed.

To reiterate, Strategist does not develop a full “cost of service” (COS) profile. It considers only costs that change from plan to plan, not costs that are fixed, such as embedded costs of existing generating capacity or distribution costs. Transmission costs are included only to the extent that they are associated with new generating capacity. Specifically, Strategist includes and ultimately recognizes in its “incremental revenue requirement” output profile:

Fixed costs of capacity additions, i.e. carrying charges on capacity and associated transmission based on a weighted average cost of capital (WACC) and fixed O&M

Fixed costs of any capacity purchases

Variable costs of the entire fleet of existing and any added units. This includes fuel, purchased energy, the market replacement cost of emission allowances (SO2 and NOX, and CO2 in appropriate cases), and variable O&M costs. In addition, revenue from external energy transactions (Off-System Sales) is netted against these costs

Due to the netting of Off-System Sales revenues against variable costs, depending on the market spreads for energy, Strategist outcomes can represent relative "longer" or "shorter" market energy positions that can have significant bearing on the resulting net system cost and determination of a least-cost plan.

In summary, Strategist models the approach AEP uses to determine jurisdictional generation revenue requirements at an integrated, system level. For the purpose of comparing plans, these costs are expressed on a Cumulative Present Worth (CPW) basis for each plan, using standard calculation methods and a 9.0% WACC.

Overview of Need for Modeling Constraints

In the PROVIEW module of Strategist, the least-cost expansion plan is empirically formulated from hundreds of thousands of possible resource alternative combinations created by the module’s chronological “dynamic programming” algorithm. On an annual basis, each capacity resource alternative combination that satisfies its least-cost objective function through user-defined constraints (in this case, a “minimum” on-going capacity reserve margin) is considered to be a feasible state and is saved by the program for consideration in following years. As the years progress, the previous years’ feasible states are used as starting points for the addition of more resources that can be used to meet the current year’s minimum reserve requirement. As the need for additional capacity on the system increases, the number of possible combinations as well as the number of feasible states increases approximately exponentially with the number of resource alternatives being considered.



139

Exhibit A-9 offers a very simplistic example of this algorithm. The model has the choice of two capacity types (CT and CC) and must achieve its reserve requirement constraint through some economic combination of the capacity types over a three- year period. Six unique plans result after the elimination of one of the more expensive paths.

C T ($1)

C C ($3)

Y ear 1

C T ($3)

C C ($4)

C T ($5)

C C ($6)

Y ear 2

C T ($5)

C C ($6)

C T ($7)

C T ($9)

C C ($10)

C C ($8)

Y ear 3

As can be seen in this example, the potential for creating hundreds of thousands of alternative combinations and feasible states can become an extremely large computational and data storage problem, if not constrained in some manner. The Strategist model includes a number of input variables specifically designed to allow the user to further limit or constrain the size of the problem the model is attempting to solve. Several of these variables focus on limiting the number of a particular resource alternative that can be considered by the model during the Planning Period. In addition, other variables limit the years that a particular alternative is available for selection by the model.

* Note: Path “CC (Yr.1)” - CT (Yr.2)” eliminated from further consideration in Yr.3 because its cumulative cost ($5) is greater than a similar path - “CT (Yr. 1) - CC (Yr. 2)” costing $4

Exhibit A-9 Strategist chronological “dynamic programming” algorithm



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Appendix M, Utility Risk Simulation Analysis (URSA) Modeling

The risk analysis of the five alternative IRP plans was done with the "Utility Risk Simulation Analysis" model (URSA), which was developed by AEP's Risk Management group. URSA was designed not only to estimate the risk in IRP plans but also to quantify one-year-ahead Earnings at Risk and for a variety of other risk-analytic purposes.

URSA is a Monte Carlo simulation model that represents the daily operation of AEP's assets under a large number of possible alternative futures. As noted above, for the IRP risk analysis, 1,399 alternative futures, each with its own, unique set of daily realizations of risk factors, were treated.

URSA is similar to a physical planning model such as Power Cost Inc.'s Gentrader, but it implements some computational economies to permit consideration of so many alternative futures. Notably, URSA treats only the peak and off peak periods of each day, not each hour. On the other hand, URSA does not reckon with "typical weeks" as many other structural models do, but rather treats explicitly each day of each alternative future. The aim of this approach is to produce a realistic depiction of unit commitment and dispatch.

1. Risk Factor Simulation

The risk analysis begins with a simulation of the daily values of the risk factors for each day of the period 2009-2020, for 1,399 alternative possible futures.

The price and load risk factors vary from day to day within each possible future in accordance with the outcomes of an analysis of the historical variations in these factors, including serial- and cross-correlation, and their relationship to the weather. The raw results obtained from the risk factor model are scaled to ensure that in each simulated year and month, the monthly means of the simulated risk factors agree with the economic forecast of these prices and loads, upon which the IRP is based.

The unit-specific outages also vary from day to day, but independently of the price and load risk factors. Unit outages are determined by a simple, binomial model that depends on the assumed rate of availability for the given unit and an assumed number of days out in case of forced outage. Simulated over many cases, the binomial model produces, for the given unit, an average rate of availability equal to the assumed rate.

2. Utility Operations in View of Given Risk Factors

On each day such day, the risk factors take on given values; AEP and its counterparties then act optimally to exercise any optionality that they may have; physical and financial results of these actions are then calculated and recorded; and the simulation proceeds to the next day.

The optionality in AEP's asset portfolio includes:

to commit or not to commit any given thermal generating unit to the grid,

to exercise or not to exercise any power purchase or sale options that it may own,

how much power to produce from each committed thermal unit,

how much water to run down, or pump up, at the Smith Mountain Hydro Pumped Storage facility,

whether and in which direction to transmit power along the AEP West tie.



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Under PJM commercial relations, much of this optionality is, in fact, exercised by PJM on AEP's behalf, based on structured commercial bids submitted to PJM by AEP. But it is assumed that the result of the bidding process and PJM's consequent decision-making is the same as if AEP were making these decisions optimally on its own behalf.

3. Representation of the Utility

a. Businesses

The URSA model divides AEP into three businesses:

retail power supply,

wholesale power supply and

fuel supply,

each with its own set of activities and financial results. This division is a schematic one and does not correspond precisely to actual business divisions of AEP. Since, as explained below, fuel and allowance contracts are not treated in the IRP, the fuel supply business's role in the IRP simulations is merely to buy fuel and allowances at market and transfer them to the units. This always results in zero net revenues for the fuel supply business.

The total required revenues of the three businesses are the required revenues of AEP as a whole. Typically the activities of the wholesale business diminish, or make a negative contribution to, required revenue. Those of the retail business, which is responsible of the costs of supplying the native load, typically make a positive contribution to net revenue. The contribution of the fuel supply business is zero, since any fuel or allowances purchased at spot are immediately transferred at the same price.

The model does not treat AEP's transmission or distribution activities, or the corresponding revenues and expenditures. These are assumed to be the same for each IRP case considered.

In any case, the IRP risk analysis, in contrast to some other risk analyses to which this same model is applied, has little to do with these schematic divisions of AEP. Therefore, while the model produces business-specific results, IRP risk results are reported for AEP in total and not by business.

b. Assets

As reckoned with in this study, AEP's East assets consist of:

thermal (steam and combustion) generating units,

Smith Mountain pumped storage facility, and

power purchase and sales contracts.

For analytical convenience, the model treats AEP's hydro generation, other than hydro pumped storage, as a power purchase contract with quantities supplied on a fixed schedule. For the purposes of the study, the returns to AEP's fuel purchase contracts, which typically expire within the next few years, are not treated. Instead, fuel expenditures are reckoned as if all fuel were purchased at spot. Also, returns to AEP's endowment of emissions allowances are not treated; here as with fuel, AEP's expenditures are reckoned at the simulated spot price.



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c. Power Supply Obligations

The two power supply businesses are responsible for different sets of power sales contracts. For the East, the sales contracts of the retail power supply business are:

AEP East load served on a tariff basis

Buckeye Power

the 250 MW tie to AEP West, which is modeled as a call option owned by the West

Those of the East wholesale power supply business are:

certain municipals served on a full requirements basis and connected to the AEP grid,

Total power delivery obligations under all power sales contracts constitute the total load of the utility.

d. Power Supply Resources

To satisfy these obligations, the two power supply businesses jointly operate a given set of power generating units and manage a given set of power purchase contracts. The generating units are:

the AEP East fleet of steam and combustion generating units and

the Smith Mountain pumped storage facility.

The power purchase contracts are:

the AEP East hydro units (which are modeled as a power purchase contract),

both East, some capacity purchases during early future years,

a set of power purchase contracts with OVEC, and

some small sources of supply such as Summersville.

The capacity purchases contribute to the satisfaction of the operating reserve requirement for AEP East in total. But any energy that would flow from these suppliers is treated as a spot power purchase, not a contractual one.

The retail power supply business, as modeled, has the first call on all power supply resources, and takes the most economical opportunities. In each period, it specifies the energy that it takes from each generating unit and power purchase contract so as to satisfy exactly its total obligations under its power sales contracts while minimizing the cost of doing so. The retail business does not normally engage in spot power sales, but it will purchase spot power whenever doing so would reduce cost.

The wholesale power supply business, as modeled, has the second call on all power supply resources, taking energy from generating units and from power supply contracts only to the extent that anything is left by the retail business. It does this so as to maximize total net revenues from sales (which effectively minimizes AEP's required revenue). It engages freely in spot power sales.

e. Spot Power Supply

The difference between the total power generated or taken under purchase contracts on the one hand, and the total deliveries required under power sales contracts on the other, defines the utility's



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net spot market sales. URSA does not treat explicitly any short-term power deals not resulting in physical delivery. Effectively, trading activities apart from purchases or sales of physical power at spot are assumed to yield a zero net return.

Because the wholesale power supply business has the second and last call on the resources able to deliver power, it determines the total power produced. By this means it effectively also determines net spot power sales of the total utility. For example, if the retail business decides upon a net spot purchase of 100 MWh, and the final dispatch implies a net spot sale of 200 MWh, then the wholesale business sells 300 MWh at spot: the 100 MWh purchased by the retail business plus an additional 200 MWh to other purchasers.

4. Reckoning of Costs

a. Transfer Pricing

URSA's design lays some emphasis upon the appropriate prices for valuing transfers between different business units. This permits economically correct estimation of the revenue requirement contributed by each asset, and of the associated risk. But since any scheme of transfer prices nets out in total, the particular scheme employed has no effect on the estimation of costs for AEP East.

The value at which power is transferred from a generating unit to a power supply business employing it is correctly reckoned at the spot price. The gain or loss that may arise if this same power is sold at a contracted price does not belong to the generating unit, but to the given power supply contract, here viewed as an asset of the given power supply business. This applies even if the "contract" in question is the obligation to serve the retail load. This implies that any generating unit considered separately, which typically does not run unless it is in the money, makes a negative contribution toward (diminishes) required revenue. On the other hand, the power sales "deal" that represents the obligation to serve makes a substantial positive contribution to required revenue.

Based on these and analogous considerations, the following transfer prices apply:

thermal generating units

o buy fuel at the spot price,

o buy emissions allowances at the spot price, and

o sell power at the spot price;

Smith Mountain

o buys power at the spot price and

o sells power at the spot price;

power purchase contracts

o buy power at the contract price and

o sell power at the spot price;

power sales contracts

o buy power at the spot price and

o sell power at the contract price



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A consequence of these conventions is that all required revenue is due to assets, and in particular, the gains from spot power sales are due to the sources of the power sold, which are the generating units and power purchase contracts employed to produce the sold power.

It is worth repeating that for the utility in total, these transfer pricing considerations wash away.

b. Operating Companies

Because the AEP East system is fully integrated, and because the interest of the risk analysis is with total East required revenue, the analysis pays no attention to operating companies, but only simulates power supply activities and financial returns for AEP East in total.

c. Calculation of Required Revenue

Required revenue is the sum of all costs minus all revenues. Revenues from serving native load are assumed to be zero; that from transmitting on the AEP West tie is assume to be the difference in East-West power prices times the quantity transmitted; and those from supplying other power sales deals are assumed to be exactly the same as the cost of the power supplied. Since no fuel or allowance deals are reckoned with, there is no revenue from these sources. If a megawatt-hour is produced at some unit and supplied to the native load, the unit is credited with the market value of the power, but the load is correspondingly debited, and what is left in total is only the cost of producing the power. If the power is supplied to some other power sales deal then the profit, since the contract revenue is assumed to equal the cost of the power delivered, is the difference between the spot power price and the cost of producing the power supplied. The gain is the same if the power is supplied directly to the spot market. Hence, in aggregate, required revenue is the cost of satisfying the obligation to serve (including the West tie), minus the profits of selling, at spot, all other power produced.

d. Treatment of Contract Revenue -- Differences from Strategist Model

It was just said that URSA assumes that the fees obtained from the customer for external transactions are always precisely the same as the cost of providing the power. The reason is to wash these sales of possible gain or loss, and thus to purge from the risk analysis any risk due to external transactions. The risk analysis thus considers only risk arising from the obligation to serve the native load.

This assumption with regard to contract revenues differs from assumptions used in the Strategist analysis, which is used to develop the IRP plans. There, particular contractual prices are assumed for the various deals and are used to determine total contract revenues. The assumptions used in the risk analysis result in greater contract revenues on power sales, with the result that in total, URSA analysis calculates a smaller net present value required revenue for the period 2006-2030 than Strategist does. This is merely for purposes of the risk analysis and is not intended to supercede the Strategist estimate.

On the contrary, the Strategist assumption with regard to contract revenues is better for estimating total, net present value required revenue; while the URSA assumption is better for analyzing risks that arise particularly from the obligation to serve the native load.



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5. Technical Comparison of URSA with Strategist

In late 2005 and early 2006, AEP's Risk Management and Corporate Planning groups collaborated in a technical comparison of detailed results from URSA and from Strategist under equivalent input assumptions. The inquiry particularly focused on costs and rates of operation (capacity factors) at AEP East and West generating units; and on total system power exports and imports, and associated revenues.

The conclusion was that for the same inputs, the two models substantially agreed in the rates of operation of AEP's various units, and in the associated costs. The main difference was that marginal, mid-stack units tend to be operated somewhat less by URSA than by Strategist. The reason for this is that URSA, with its daily unit commitment paradigm, cherry-picks short sequences of favorable days when these units will be committed. This optionality is not available within Strategist's "typical week" framework, and Strategist therefore tends to commit such units during the entire week, and to keep them running at minimum during unfavorable periods. This difference does not, however, impede the use of URSA to analyze the risk around cases developed using Strategist. In any case, since there is very little mid-stack capacity in AEP's East fleet, this difference is material mainly to the analysis of the West fleet.

URSA and Strategist produced very similar estimates of power imports and exports for AEP East; for AEP West, URSA produced marginally smaller estimates of exports and larger estimates of imports, due to the marginally lower rate at which it operated the West's relatively substantial holding of mid-stack units.


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